As filed with the Securities and Exchange Commission on August 24, 2012
Registration No. 333-_______
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form S-4
REGISTRATION STATEMENT
UNDER THE SECURITIES ACT OF 1933
DPL INC.
(Exact Name of Registrant as Specified in Its Charter)
Ohio | 4931 | 31-1163136 |
(State or Other Jurisdiction of Incorporation or Organization) | (Primary Standard Industrial Classification Code Number) | (I.R.S. Employer Identification No.) |
1065 Woodman Drive Dayton, OH 45432 (937) 224-6000 | ||
(Address, Including Zip Code, and Telephone Number, Including Area Code, of Registrant’s Principal Executive Offices) |
Timothy G. Rice Vice President, Acting General Counsel and Corporate Secretary DPL Inc. 1065 Woodman Drive Dayton, OH 45432 (937) 224-6000 | ||
(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent For Service) |
Copies to: | ||
Richard D. Truesdell, Jr., Esq. Davis Polk & Wardwell LLP 450 Lexington Avenue New York, New York 10017 (212) 450-4000 |
Approximate date of commencement of proposed sale to the public: As soon as practicable after the effective date of this Registration Statement.
If the securities being registered on this Form are being offered in connection with the formation of a holding company and there is compliance with General Instruction G, check the following box: o
If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o_________________________________________________
If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer o Accelerated filer o
Non-accelerated filer x (Do not check if a smaller reporting company) Smaller reporting company o
CALCULATION OF REGISTRATION FEE | |||||
Title Of Each Class Of Securities To Be Registered | Amount To Be Registered | Proposed Maximum Offering Price Per Unit(1) | Proposed Maximum Aggregate Offering Price(1) | Amount Of Registration Fee | |
New 6.50% Senior Notes due 2016 | $450,000,000 | 100% | $450,000,000 | $ 51,570 | |
New 7.25% Senior Notes due 2021 | $800,000,000 | 100% | $800,000,000 | $ 91,680 |
(1) | Estimated solely for the purpose of calculating the amount of the registration fee pursuant to Rule 457 under the Securities Act of 1933. |
The registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended or until the Registration Statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.
The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and we are not soliciting offers to buy these securities in any jurisdiction where the offer or sale is not permitted.
PROSPECTUS (SUBJECT TO COMPLETION, DATED AUGUST 24, 2012)
DPL Inc.
Offer to Exchange
6.50% Senior Notes due 2016
7.25% Senior Notes due 2021
for
New 6.50% Senior Notes Due 2016
New 7.25% Senior Notes due 2021
We are offering to exchange up to $450,000,000 of our new registered 6.50% Senior Notes due 2016 (the “New 2016 Notes”) for up to $450,000,000 of our existing unregistered 6.50% Senior Notes due 2016 (the “Old 2016 Notes”) and up to $800,000,000 of our new registered 7.25% Senior Notes due 2021 (the “New 2021 Notes,” and together with the New 2016 Notes, the “new notes”) for up to $800,000,000 of our existing unregistered 7.25% Senior Notes due 2021 (the “Old 2021 Notes,” and together with the Old 2016 Notes, the “old notes”). The terms of the new notes are identical in all material respects to the terms of the old notes, except that the new notes have been registered under the Securities Act of 1933, as amended (the “Securities Act”), and the transfer restrictions and registration rights relating to the old notes do not apply to the new notes. The new notes will represent the same debt as the old notes and we will issue the new notes under the same indenture.
To exchange your old notes for new notes:
· | you are required to make the representations described on page 4 to us; and |
· | you should read the section called “The Exchange Offer” starting on page 155 for further information on how to exchange your old notes for new notes. |
The exchange offer will expire at 11:59 P.M. New York City time on , 2012 unless it is extended.
See “Risk Factors” beginning on page 8 of this prospectus for a discussion of risk factors that should be considered by you prior to tendering your old notes in the exchange offer.
Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of the securities to be issued in the exchange offer or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.
, 2012
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ANNEX-II |
________________________________
We have not authorized anyone to provide you with any information other than that contained in this prospectus or to which we have referred you. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. You should assume that the information appearing in this prospectus is accurate only as of the date on the front cover of this prospectus. Our business, financial condition, results of operations and prospects may have changed since that date.
This prospectus is based on information provided by us and by other sources that we believe are reliable. We cannot assure you that this information is accurate or complete. This prospectus summarizes certain documents and other information and we refer you to them for a more complete understanding of what we discuss in this prospectus. In making an investment decision, you must rely on your own examination of our company and the terms of the offering and the notes, including the merits and risks involved.
We are not making any representation to any purchaser of the notes regarding the legality of an investment in the notes by such purchaser under any legal investment or similar laws or regulations. You should not consider any information in this prospectus to be legal, business or tax advice. You should consult your own attorney, business advisor and tax advisor for legal, business and tax advice regarding an investment in the notes.
Neither the Securities and Exchange Commission (“SEC”) nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.
NOTICE TO NEW HAMPSHIRE RESIDENTS
NEITHER THE FACT THAT A REGISTRATION STATEMENT OR AN APPLICATION FOR A LICENSE HAS BEEN FILED UNDER CHAPTER 421-B OF THE NEW HAMPSHIRE REVISED STATUTES ANNOTATED, 1995, AS AMENDED, WITH THE STATE OF NEW HAMPSHIRE NOR THE FACT THAT A SECURITY IS EFFECTIVELY REGISTERED OR A PERSON IS LICENSED IN THE
STATE OF NEW HAMPSHIRE CONSTITUTES A FINDING BY THE SECRETARY OF STATE OF NEW HAMPSHIRE THAT ANY DOCUMENT FILED UNDER RSA 421-B IS TRUE, COMPLETE AND NOT MISLEADING. NEITHER ANY SUCH FACT NOR THE FACT THAT AN EXEMPTION OR EXCEPTION IS AVAILABLE FOR A SECURITY OR A TRANSACTION MEANS THAT THE SECRETARY OF STATE HAS PASSED IN ANY WAY UPON THE MERITS OR QUALIFICATIONS OF, OR RECOMMENDED OR GAVE APPROVAL TO, ANY PERSON, SECURITY, OR TRANSACTION. IT IS UNLAWFUL TO MAKE, OR CAUSE TO BE MADE, TO ANY PROSPECTIVE PURCHASER, CUSTOMER, OR CLIENT ANY REPRESENTATION INCONSISTENT WITH THE PROVISIONS OF THIS PARAGRAPH.
GLOSSARY OF TERMS
The following select abbreviations or acronyms are used in this Prospectus:
Abbreviation or Acronym | Definition |
AES | The AES Corporation, a global power company, the ultimate parent company of DPL |
AMI | Advanced Metering Infrastructure |
AOCI | Accumulated Other Comprehensive Income |
ARO | Asset Retirement Obligation |
ASU | Accounting Standards Update |
CAA | Clean Air Act |
CAIR | Clean Air Interstate Rule |
CCEM | Customer Conservation and Energy Management |
CFTC | Commodity Futures Trading Commission |
CO2 | Carbon Dioxide |
CRES | Competitive Retail Electric Service |
CSAPR | Cross-State Air Pollution Rule |
CSP | Columbus Southern Power Company, a subsidiary of American Electric Power Company, Inc. (“AEP”). Columbus Southern Power Company merged into the Ohio Power Company, another subsidiary of AEP, effective December 31, 2011 |
DPL | DPL Inc. |
DPLE | DPL Energy, LLC, a wholly owned subsidiary of DPL that owns and operates peaking generation facilities from which it makes wholesale sales |
DPLER | DPL Energy Resources, Inc., a wholly owned subsidiary of DPL which sells competitive electric energy and other energy services |
DP&L | The Dayton Power and Light Company, the principal subsidiary of DPL and a public utility which sells electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio |
Duke Energy | Duke Energy Ohio, Inc., formerly The Cincinnati Gas & Electric Company (CG&E) |
EIR | Environmental Investment Rider |
EPS | Earnings Per Share |
ESOP | Employee Stock Ownership Plan |
ESP | Electric Security Plans, filed with the PUCO, pursuant to Ohio law |
ESP Stipulation | A Stipulation and Recommendation filed by DP&L with the PUCO on February 24, 2009 regarding DP&L’s ESP filing pursuant to SB 221. The Stipulation was signed by the Staff of the PUCO, the Office of the Ohio Consumers’ Counsel and various intervening parties. The PUCO approved the Stipulation on June 24, 2009. |
FASB | Financial Accounting Standards Board |
Abbreviation or Acronym | Definition |
FASC | FASB Accounting Standards Codification |
FASC 805 | FASB Accounting Standards Codification 805, “Business Combinations” |
FERC | Federal Energy Regulatory Commission |
FGD | Flue Gas Desulfurization |
Form 10-K | DPL’s and DP&L’s combined Annual Report on Form 10-K/A for the fiscal year ending December 31, 2011, which was filed on March 28, 2012 |
FTRs | Financial Transmission Rights |
GAAP | Generally Accepted Accounting Principles in the United States of America |
GHG | Greenhouse Gas |
IFRS | International Financial Reporting Standards |
kWh | Kilowatt hours |
MC Squared | MC Squared Energy Services, LLC, a retail electricity supplier wholly owned by DPLER which was purchased on February 28, 2011 |
Merger | The merger of DPL and Dolphin Sub, Inc. (a wholly owned subsidiary of AES) in accordance with the terms of the Merger agreement. At the Merger date, Dolphin Sub, Inc. was merged into DPL, leaving DPL as the surviving company. As a result of the Merger, DPL became a wholly owned subsidiary of AES. |
Merger agreement | The Agreement and Plan of Merger dated April 19, 2011 among DPL, The AES Corporation (“AES”), and Dolphin Sub, Inc., a wholly owned subsidiary of AES, whereby AES agreed to acquire DPL for $30 per share in a cash transaction valued at approximately $3.5 billion plus the assumption of $1.2 billion of existing debt. Upon closing, DPL became a wholly owned subsidiary of AES. |
Merger date | November 28, 2011, the date of the closing of the merger of DPL and Dolphin Sub, Inc., a wholly owned subsidiary of AES. |
MRO | Market Rate Option, a plan available to be filed with the PUCO pursuant to Ohio law |
MTM | Mark to Market |
MVIC | Miami Valley Insurance Company, a wholly owned insurance subsidiary of DPL that provides insurance services to DPL and its subsidiaries and, in some cases, insurance services to partner companies related to jointly owned facilities operated by DP&L |
NERC | North American Electric Reliability Corporation |
NOV | Notice of Violation |
NOx | Nitrogen Oxide |
NPDES | National Pollutant Discharge Elimination System |
NYMEX | New York Mercantile Exchange |
OAQDA | Ohio Air Quality Development Authority |
Ohio EPA | Ohio Environmental Protection Agency |
OTC | Over-The-Counter |
Abbreviation or Acronym | Definition |
OVEC | Ohio Valley Electric Corporation, an electric generating company in which DP&L holds a 4.9% equity interest |
PJM | PJM Interconnection, LLC, a regional transmission organization |
Predecessor | DPL prior to November 28, 2011, the date AES acquired DPL |
PRP | Potentially Responsible Party |
PUCO | Public Utilities Commission of Ohio |
RSU | Restricted Stock Units |
RTO | Regional Transmission Organization |
RPM | Reliability Pricing Model |
SB 221 | Ohio Senate Bill 221, an Ohio electric energy bill that was signed by the Governor on May 1, 2008 and went into effect July 31, 2008. This law required all Ohio distribution utilities to file either an ESP or MRO to be in effect January 1, 2009. The law also contains, among other things, annual targets relating to advanced energy portfolio standards, renewable energy, demand reduction and energy efficiency standards. |
SCR | Selective Catalytic Reduction |
SEC | Securities and Exchange Commission |
SECA | Seams Elimination Charge Adjustment |
SERP | Supplemental Executive Retirement Plan |
SO2 | Sulfur Dioxide |
SO3 | Sulfur Trioxide |
SSO | Standard Service Offer which represents the regulated rates, authorized by the PUCO, charged to DP&L retail customers within DP&L’s service territory |
Successor | DPL after its acquisition by AES |
TCRR | Transmission Cost Recovery Rider |
USEPA | U.S. Environmental Protection Agency |
USF | Universal Service Fund |
VRDN | Variable Rate Demand Note |
This summary highlights information contained elsewhere in this prospectus. This summary may not contain all of the information that may be important to you. You should read this entire prospectus before making a decision to exchange your old notes for new notes, including the section entitled “Risk Factors” beginning on page 8 of this prospectus.
Unless otherwise indicated or the context otherwise requires, the terms “DPL,” we,” “our,” “us,” and “the Company” refer to DPL Inc., including all of its subsidiaries and affiliates, collectively.
Our Company
We are a diversified regional energy company that serves over 500,000 retail customers in West Central Ohio and Illinois through our subsidiaries, DP&L, which comprises our Utility segment, and DPL Energy Resources, Inc. (“DPLER”), which comprises our Competitive Retail segment.
DP&L, a public utility incorporated in 1911 under the laws of Ohio, sells electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio. Electricity for DP&L’s 24 county service area is primarily generated at eight coal-fired power plants and is distributed to more than 500,000 retail customers. The principal industries that it serves include automotive, food processing, paper, plastic, manufacturing and defense. DP&L’s sales reflect general economic and competitive conditions, and seasonal weather patterns of the area. DP&L sells any excess energy and capacity into the wholesale market. DP&L also sells electricity to DPLER, an affiliate, to satisfy the electric requirements of its retail customers.
DPLER sells competitive retail electric service, under contract, to residential, commercial and industrial customers. DPLER’s operations include those of its wholly owned subsidiary, MC Squared, which was acquired on February 28, 2011. DPLER has approximately 70,000 customers currently located throughout Ohio and Illinois. DPLER does not own any transmission or generation assets, and all of DPLER’s electric energy was purchased from DP&L or PJM to meet its sales obligations. DPLER’s sales reflect the general economic conditions and seasonal weather patterns of the areas it serves.
Our other significant subsidiaries include DPLE, which owns and operates peaking generating facilities from which it makes wholesale sales of electricity and MVIC, our captive insurance company that provides insurance services to us and our subsidiaries. All of DPL’s subsidiaries are wholly owned.
We strive to achieve disciplined growth in energy margins while limiting volatility in both cash flows and earnings, and to achieve stable, long-term growth through efficient operations and strong customer and regulatory relations. More specifically, our strategy is to match energy supply with load, or customer demand, to help maximize profits while effectively managing exposure to movements in energy and fuel prices and utilizing the transmission and distribution assets that transfer electricity at the most efficient cost, and to maintain the highest level of customer service and reliability.
DPL Inc. was incorporated under the laws of the State of Ohio in 1985. Our principal executive office is located at 1065 Woodman Drive, Dayton, Ohio, 45432, and its telephone number is (937) 224-6000. Our website address is http://www.dplinc.com. Material contained on our website is not part of and is not deemed to be a part of this prospectus.
DPL Inc. is a wholly owned indirect subsidiary of The AES Corporation (“AES”). AES is a global power company. AES’s executive offices are located at 4300 Wilson Boulevard, Arlington, VA, 22203 and its telephone number is (703) 522-1315.
The names “DPL,” “The Dayton Power & Light Company” and various other names contained herein are DPL owned trademarks, service marks or trade names. The name “AES” is an AES owned trademark, service mark or trade name. All other trademarks, trade names or service marks appearing herein are owned by their respective holders.
The Exchange Offer
Securities Offered | We are offering up to $450,000,000 aggregate principal amount of new 6.50% Senior Notes due 2016 (the “New 2016 Notes”) and up to $800,000,000 aggregate principal amount of new 7.25% Senior Notes due 2021 (the “New 2021 Notes,” and together with the New 2016 Notes, the “new notes”), which will be registered under the Securities Act. |
The Exchange Offer | We are offering to issue the new notes in exchange for a like principal amount of your old notes. We are offering to issue the new notes to satisfy our obligations contained in the registration rights agreement entered into when the old notes were sold in transactions permitted by Rule 144A and Regulation S under the Securities Act and therefore not registered with the SEC. For procedures for tendering, see “The Exchange Offer.” |
Tenders, Expiration Date, Withdrawal | The exchange offer will expire at 11:59 P.M. New York City time on , 2012 unless it is extended. If you decide to exchange your old notes for new notes, you must acknowledge that you are not engaging in, and do not intend to engage in, a distribution of the new notes. If you decide to tender your old notes in the exchange offer, you may withdraw them at any time prior to , 2012. If we decide for any reason not to accept any old notes for exchange, your old notes will be returned to you without expense to you promptly after the exchange offer expires. You may only exchange old notes in denominations of $2,000 and integral multiples of $1,000 in excess thereof. |
U.S. Federal Income Tax Consequences | Your exchange of old notes for new notes in the exchange offer will not result in any income, gain or loss to you for U.S. federal income tax purposes. See “U.S. Federal Income Tax Consequences of the Exchange Offer.” |
Use of Proceeds | We will not receive any proceeds from the issuance of the new notes in the exchange offer. |
Exchange Agent | Wells Fargo Bank, N.A. is the exchange agent for the exchange offer. |
Failure to Tender Your Old Notes | If you fail to tender your old notes in the exchange offer, you will not have any further rights under the registration rights agreement, including any right to require us to register your old notes or to pay you additional interest or liquidated damages. All untendered old notes will continue to be subject to the |
restrictions on transfer set forth in the old notes and in the indenture. In general, the old notes may not be offered or sold, unless registered under the Securities Act, except pursuant to an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. We do not currently anticipate that we will register such untendered old notes under the Securities Act and, following this exchange offer, will be under no obligation to do so. |
You will be able to resell the new notes without registering them with the SEC if you meet the requirements described below.
Based on interpretations by the SEC’s staff in no-action letters issued to third parties, we believe that new notes issued in exchange for the old notes in the exchange offer may be offered for resale, resold or otherwise transferred by you without registering the new notes under the Securities Act or delivering a prospectus, unless you are a broker-dealer receiving securities for your own account, so long as:
· | you are not one of our “affiliates,” which is defined in Rule 405 of the Securities Act; |
· | you acquire the new notes in the ordinary course of your business; |
· | you do not have any arrangement or understanding with any person to participate in the distribution of the new notes; and |
· | you are not engaged in, and do not intend to engage in, a distribution of the new notes. |
If you are an affiliate of DPL, or you are engaged in, intend to engage in or have any arrangement or understanding with respect to, the distribution of new notes acquired in the exchange offer, you (1) should not rely on our interpretations of the position of the SEC’s staff and (2) must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction.
If you are a broker-dealer and receive new notes for your own account in the exchange offer:
· | you must represent that you do not have any arrangement with us or any of our affiliates to distribute the new notes; |
· | you must acknowledge that you will deliver a prospectus in connection with any resale of the new notes you receive from us in the exchange offer; the letter of transmittal states that by so acknowledging and by delivering a prospectus, you will not be deemed to admit that you are an “underwriter” within the meaning of the Securities Act; and |
· | you may use this prospectus, as it may be amended or supplemented from time to time, in connection with the resale of new notes received in exchange for old notes acquired by you as a result of market-making or other trading activities. |
For a period of 90 days after the expiration of the exchange offer, we will make this prospectus available to any broker-dealer for use in connection with any resale described above.
Summary Description of the Notes
The terms of the new notes and the old notes are identical in all material respects, except that the new notes have been registered under the Securities Act, and the transfer restrictions and registration rights relating to the old notes do not apply to the new notes. The new notes will represent the same debt as the old notes and will be governed by the same indenture under which the old notes were issued.
Issuer | DPL Inc. |
Notes Offered | $450,000,000 aggregate principal amount of New 2016 Notes |
$800,000,000 aggregate principal amount of New 2021 Notes | |
Maturity | October 15, 2016 for the New 2016 Notes |
October 15, 2021 for the New 2021 Notes | |
Interest Payment Dates | The New 2016 Notes will bear interest at an annual rate equal to 6.50%. Interest on the notes will be paid on each April 15 and October 15, beginning on October 15, 2012. |
The New 2021 Notes will bear interest at an annual rate equal to 7.25%. Interest on the notes will be paid on each April 15 and October 15, beginning on October 15, 2012. | |
Record Dates | The regular record date for each interest payment date for each series of notes will be the close of business on the 15th calendar day prior to such interest payment date. |
Denominations | Minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof. |
Ranking | The notes are our unsecured and unsubordinated obligations and will rank: |
· equal in right of payment with all of our other senior unsecured debt; | |
· effectively junior in right of payment to (a) our secured debt to the extent of the value of the assets securing such debt and (b) the debt and other liabilities (including trade payables) of our subsidiaries; and | |
· senior in right of payment to our subordinated debt. | |
As of June 30, 2012: | |
· We had, on a consolidated basis, approximately |
$1,713.2 million of senior unsecured debt, $906.4 million of secured debt and no subordinated debt outstanding; | |
· DPL had, on an unconsolidated basis, approximately $1,694.7 million of senior unsecured debt, and no secured debt or subordinated debt outstanding; and | |
· Our subsidiaries had approximately $2,196.3 million of debt and other liabilities, including trade payables, outstanding. | |
The indenture under which the notes will be issued contains no restrictions on the amount of additional unsecured indebtedness that we may incur or the amount of indebtedness (whether secured or unsecured) that our subsidiaries may incur. | |
There will be no recourse against AES with respect to the notes offered. | |
Optional Redemption | Prior to September 15, 2016 (one month before the maturity date) with respect to the New 2016 Notes or July 15, 2021 (three months before the maturity date) with respect to the New 2021 Notes, we may redeem some or all of the New 2016 Notes or New 2021 Notes, as applicable, at 100% of the principal amount of the notes being redeemed plus a “make-whole” amount. |
At any time on or after September 15, 2016 with respect to the New 2016 Notes or July 15, 2021 with respect to the New 2021 Notes, we may redeem some or all of the New 2016 Notes or New 2021 Notes, as applicable, at 100% of the principal amount of the notes being redeemed. See “Description of the Notes—Optional Redemption.” | |
Change of Control | Upon the occurrence of a change of control triggering event (as described in “Description of the Notes—Repurchase at the Option of Holders”), you may require the repurchase of some or all of your notes at 101% of their principal amount, plus accrued and unpaid interest to the date of repurchase. |
Covenants | The indenture governing the notes contains covenants that, among other things, limit our ability and, in the case of restrictions on liens, the ability of our significant subsidiaries to: |
· create certain liens on assets and properties; and | |
· consolidate or merge, or convey, transfer or |
lease substantially all of our consolidated properties and assets. | |
These covenants are subject to important exceptions and qualifications, which are described in “Description of Notes—Covenants.” The indenture does not in any way restrict or prevent DP&L or any other subsidiary from incurring indebtedness. | |
Book-Entry Form | The notes will be issued in registered book-entry form represented by one or more global notes to be deposited with or on behalf of The Depository Trust Company (“DTC”) or its nominee. Transfers of the notes will be effected only through the facilities of DTC. Beneficial interests in the global notes may not be exchanged for certificated notes except in limited circumstances. See “Description of Notes—Global Notes.” |
Trustee, Registrar and Paying Agent | Wells Fargo Bank, N.A. |
If any of the following risks occur, our business, results of operations or financial condition could be materially adversely affected. You should also read the section captioned “Cautionary Note Regarding Forward-Looking Statements” for a discussion of what types of statements are forward-looking as well as the significance of such statements in the context of this prospectus.
Risks Related to the Exchange Offer
If you choose not to exchange your old notes in the exchange offer, the transfer restrictions currently applicable to your old notes will remain in force and the market price of your old notes could decline.
If you do not exchange your old notes for new notes in the exchange offer, then you will continue to be subject to the transfer restrictions on the old notes as set forth in the offering memorandum distributed in connection with the private offering of the old notes. In general, the old notes may not be offered or sold unless they are registered or exempt from registration under the Securities Act and applicable state securities laws. Except as required by the registration rights agreement entered into in connection with the private offering of the old notes, we do not intend to register resales of the old notes under the Securities Act. The tender of old notes under the exchange offer will reduce the principal amount of the old notes outstanding, which may have an adverse effect upon, and increase the volatility of, the market price of the old notes due to reduction in liquidity.
You must follow the exchange offer procedures carefully in order to receive the new notes.
If you do not follow the procedures described in this prospectus, you will not receive any new notes. If you want to tender your old notes in exchange for new notes, you should allow sufficient time to ensure timely delivery. No one is under any obligation to give you notification of defects or irregularities with respect to tenders of old notes for exchange. For additional information, see the section captioned “The Exchange Offer” in this prospectus.
There are state securities law restrictions on the resale of the new notes.
In order to comply with the securities laws of certain jurisdictions, the new notes may not be offered or resold by any holder, unless they have been registered or qualified for sale in such jurisdictions or an exemption from registration or qualification is available and the requirements of such exemption have been satisfied. We currently do not intend to register or qualify the resale of the new notes in any such jurisdictions. However, generally an exemption is available for sales to registered broker-dealers and certain institutional buyers. Other exemptions under applicable state securities laws also may be available.
Risks Related to the Notes
We are a holding company and parent of DP&L and other subsidiaries. Our cash flow is dependent on the operating cash flows of DP&L and our other subsidiaries and their ability to pay cash to DPL.
We are a holding company and our investments in our subsidiaries are our primary assets. A significant portion of our business is conducted by our subsidiary, DP&L. As such, our cash flow is dependent on the operating cash flows of DP&L and its ability to pay cash to us. DP&L’s governing documents contain certain limitations on the ability to declare and pay dividends to us while preferred stock is outstanding. Certain of DP&L’s debt agreements also contain limits with respect to the ability of DP&L to loan or advance funds to us. In addition, DP&L is regulated by the PUCO that possesses broad oversight powers to ensure that the needs of utility customers are being met. As a part of a stipulation approving the Merger (as defined below) of DPL into AES, DPL agreed to restrictions that could limit dividends DP&L makes to DPL. While we do not expect any of the foregoing restrictions to significantly affect DP&L’s ability to pay funds to us in the future, a significant limitation on DP&L’s ability to pay dividends or loan or advance funds to us would have a material adverse impact on our results of operations, financial condition and cash flows, and our ability to make interest and principal payments on the notes and our other indebtedness.
Any right we have to receive any assets of any of our subsidiaries upon any liquidation, dissolution, winding up, receivership, reorganization, assignment for the benefit of creditors, marshaling of assets and liabilities or any bankruptcy, insolvency or similar proceedings (and the consequent right of the holders of our indebtedness to participate in the distribution of, or to realize proceeds from, those assets) will be effectively subordinated to the claims of any such subsidiary’s creditors (including trade creditors and holders of debt issued by such subsidiary).
Our subsidiaries are separate and distinct legal entities and, unless they have expressly guaranteed any of our indebtedness, have no obligation, contingent or otherwise, to pay any amounts due pursuant to such debt or to make any funds available whether by dividends, fees, loans or other payments. None of our subsidiaries are guaranteeing, or are otherwise obligated with respect to, the notes.
The notes will be effectively subordinated to the liabilities of our subsidiaries.
Our subsidiaries are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any amounts due on the notes or to make any funds available therefor, whether by dividends, fees, loans or other payments. Any right we have to receive any assets of any of our subsidiaries upon any liquidation, dissolution, winding up, receivership, reorganization, assignment for the benefit of creditors, marshaling of assets and liabilities or any bankruptcy, insolvency or similar proceedings (and the consequent right of the holders of our indebtedness to participate in the distribution of, or to realize proceeds from, those assets) will be effectively subordinated to the claims of any such subsidiary’s creditors (including trade creditors and holders of debt issued by such subsidiary). Accordingly, the notes will be effectively subordinated to all liabilities of our subsidiaries. At June 30, 2012, our subsidiaries had approximately $2,196.3 million of outstanding liabilities, including outstanding indebtedness. The indenture governing the notes does not limit the ability of our subsidiaries to incur additional indebtedness.
The notes will be effectively subordinated to our secured debt.
The notes will be our unsecured general obligations, and therefore will be effectively subordinated to all of our secured debt to the extent of the value of the assets securing such debt. As of June 30, 2012, on a consolidated basis, we had a total of approximately $906.4 million of secured debt outstanding. The indenture governing the notes limits but does not prohibit us from incurring additional secured debt and there are significant exceptions to this covenant. See “Description of the Notes—Covenants—Limitations on Liens.”
We may not be able to repurchase the notes upon a change of control.
Upon a change of control (as defined under “Description of the Notes—Repurchase at the Option of Holders”), we will be required to offer to repurchase all outstanding notes at 101% of their principal amount plus accrued and unpaid interest. The source of funds for any such purchase of the notes will be our available cash or cash generated from our subsidiaries’ operations or other sources, including borrowings, issuance of additional debt, sales of assets or sales of equity. We may not be able to satisfy our obligations to repurchase the notes upon a change of control because we may not have sufficient financial resources to purchase all of the notes that are tendered upon a change of control.
We may incur additional indebtedness, which may affect our financial health and our ability to repay the notes.
As of June 30, 2012, on a consolidated basis, we had $2,619.6 million of indebtedness, $906.4 million of which was secured indebtedness. This level of indebtedness and the related security could have important consequences, including the following:
· | increase our vulnerability to general adverse economic and industry conditions; |
· | require us to dedicate a substantial portion of our cash flow from operations to make payments on our indebtedness, thereby reducing the availability of our cash flow to fund other corporate purposes; |
· | limit our flexibility in planning for, or reacting to, changes in our business and industry; and |
· | limit, along with the financial and other restrictive covenants in our indebtedness, among other things, our ability to borrow additional funds, as needed. |
We and/or our subsidiaries expect to incur additional debt in the future, subject to the terms of debt agreements and regulatory approvals. To the extent we become more leveraged, the risks described above would increase. Further, our actual cash requirements in the future may be greater than expected. Accordingly, our cash flow from operations may not be sufficient to repay at maturity all of our outstanding debt as it becomes due and, in that event, we may not be able to borrow money, sell assets or otherwise raise funds on acceptable terms or at all to refinance our debt, including the notes, as it becomes due.
Credit rating downgrades could adversely affect the trading price of the notes.
The trading price for the notes may be affected by our credit rating and the credit rating of AES. Credit ratings are continually revised. Any downgrade in our credit rating or the credit rating of AES could adversely affect the trading price of the notes or the trading markets for the notes to the extent trading markets for the notes develop.
Risks Related to Our Business
Our customers have the opportunity to select alternative electric generation service providers, as permitted by Ohio legislation.
Customers can elect to buy transmission and generation service from a PUCO-certified CRES provider offering services to customers in DP&L’s service territory. DPLER, a wholly-owned subsidiary of DPL, is one of those PUCO-certified CRES providers. Unaffiliated CRES providers also have been certified to provide energy in DP&L’s service territory. Customer switching from DP&L to DPLER reduces DPL’s revenues since the generation rates charged by DPLER are less than the SSO rates charged by DP&L. Increased competition by unaffiliated CRES providers in DP&L’s service territory for retail generation service could result in the loss of existing customers and reduced revenues and increased costs to retain or attract customers. Decreased revenues and increased costs due to continued customer switching and customer loss could have a material adverse effect on our results of operations, financial condition and cash flows. The following are some of the factors that could result in increased switching by customers to PUCO-certified CRES providers in the future:
· | Low wholesale price levels have led and may continue to lead to existing CRES providers becoming more active in our service territory, and additional CRES providers entering our territory. |
· | We could experience increased customer switching through “governmental aggregation,” where a municipality may contract with a CRES provider to provide generation service to the customers located within the municipal boundaries. |
We are subject to extensive laws and local, state and federal regulation, as well as related litigation, that could affect our operations and costs.
We are subject to extensive laws and regulation by federal, state and local authorities, such as the PUCO, the CFTC, the USEPA, the Ohio EPA, the FERC, the Department of Labor and the Internal Revenue Service, among others. Regulations affect almost every aspect of our business, including in the areas of the environment, health and safety, cost recovery and rate making, the issuance of securities and incurrence of debt and taxation. New laws and regulations, and new interpretations of existing laws and regulations, are ongoing and we generally cannot predict the future course of changes in this regulatory environment or the ultimate effect that this changing regulatory environment will have on our business. Complying with this regulatory environment requires us to expend a significant amount of funds and resources. The failure to comply with this regulatory environment could subject us to substantial financial costs and penalties and changes, either forced or voluntary, in the way we operate our business. Additional detail about the effect of this regulatory environment on our operations is included in the risk factors set forth below. In the normal course of business, we are also subject to various lawsuits, actions, proceedings, claims and other matters asserted under this regulatory environment or otherwise, which require us to expend significant funds to address, the outcomes of which are uncertain and the adverse resolutions of which could have a material adverse effect on our results of operations, financial condition and cash flows.
The costs we can recover and the return on capital we are permitted to earn for certain aspects of our business are regulated and governed by the laws of Ohio and the rules, policies and procedures of the PUCO.
On May 1, 2008, SB 221, an Ohio electric energy bill, was signed by the Governor of Ohio and became effective July 31, 2008. This law, among other things, requires all Ohio distribution utilities at certain times to file an SSO either in the form of an ESP or MRO, and established a significantly excessive earnings test for Ohio public utilities that compares the utility’s earnings to the earnings of other companies with similar business and financial risks. The PUCO approved DP&L’s initial ESP on June 24, 2009. DP&L’s 2009 ESP provided, among other things, that DP&L’s existing rate plan structure would continue through the end of 2012; that DP&L may seek recovery for adjustments to its existing rate plan structure for costs associated with storm damage, regulatory and tax changes, new climate change or carbon regulations, fuel and purchased power and certain other costs; and that SB 221’s significantly excessive earnings test will apply in 2013 based upon DP&L’s 2012 earnings. On March 30, 2012, DP&L filed an MRO to establish a new rate plan and recovery structure that will phase in market-based rates over the time period January 2013 through May 2018. As filed, DP&L’s proposed MRO is expected to provide an initial rate decrease for customers and result in decreases to DP&L’s revenues that could adversely affect our results of operations, financial condition and cash flows. DP&L faces regulatory uncertainty from this MRO filing. The PUCO could accept, reject or seek to modify DP&L’s proposed MRO and/or require DP&L to propose another SSO. A new or revised SSO could result in changes to DP&L’s rate plan and recovery structure that could further adversely affect our results of operations, cash flows and financial condition. DP&L’s proposed MRO and current ESP and certain filings made by us in connection with these plans are further discussed in our periodic reports. Under the 2009 ESP, DP&L was obligated to be the provider of last resort (POLR) and supply generation service to customers located within DP&L’s service territory who do not elect service from a Competitive Retail Electric Service (CRES) Provider. DP&L was compensated for this obligation through a nonbypassable charge. Through the pending MRO filing, the PUCO may determine that the local distribution Company may no longer function as the POLR provider and thus may decrease or discontinue this nonbypassable charge, or may establish other rate designs and provisions to reflect new terms and conditions of standard offer service.
While rate regulation is premised on full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that the PUCO will agree that all of our costs have been prudently incurred or are recoverable or that the regulatory process in which rates are determined will always result in rates that will produce a full or timely recovery of our costs and permitted rates of return. Certain of our cost recovery riders are also bypassable by some of our customers who switched to a CRES provider. Accordingly, the revenue DP&L receives may or may not match its expenses at any given time. Therefore, DP&L could be subject to prevailing market prices for electricity and would not necessarily be able to charge rates that produce timely or full recovery of its expenses. Changes in, or reinterpretations of, the laws, rules, policies and procedures that set electric rates, permitted rates of return and POLR service; changes in DP&L’s rate structure and its ability to recover amounts for environmental compliance, standard offer service terms and conditions, reliability initiatives, fuel and purchased power (which account for a substantial portion of our operating costs), customer switching, capital expenditures and investments and other costs on a full or timely basis through rates; and changes to the frequency and timing of rate increases could have a material adverse effect on our results of operations, financial condition and cash flows.
Our increased costs due to advanced energy and energy efficiency requirements may not be fully recoverable in the future.
SB 221 contains targets relating to advanced energy, renewable energy, peak demand reduction and energy efficiency standards. The standards require that, by the year 2025 and each year thereafter, 25% of the total number of kWh of electricity sold by the utility to retail electric consumers must come from alternative energy resources, which include “advanced energy resources” such as distributed generation, clean coal, advanced nuclear, energy efficiency and fuel cell technology; and “renewable energy resources” such as solar, hydro, wind, geothermal and biomass. At least half of the 25% must be generated from renewable energy resources, including solar energy. Annual renewable energy standards began in 2009 with increases in required percentages each year through 2024. The advanced energy standard must be met by 2025 and each year thereafter. Annual targets for energy efficiency began in 2009 and require increasing energy reductions each year compared to a baseline energy usage, up to 22.3%
by 2025. Peak demand reduction targets began in 2009 with increases in required percentages each year, up to 7.75% by 2018. The advanced energy and renewable energy standards have increased our power supply costs and are expected to continue to increase (and could materially increase) these costs. Pursuant to DP&L’s approved ESP, DP&L is entitled to recover costs associated with its alternative energy compliance costs, as well as its energy efficiency and demand response programs. DP&L began recovering these costs in 2009. If in the future we are unable to timely or fully recover these costs, it could have a material adverse effect on our results of operations, financial condition and cash flows. In addition, if we were found not to be in compliance with these standards, monetary penalties could apply. These penalties are not permitted to be recovered from customers and significant penalties could have a material adverse effect on our results of operations, financial condition and cash flows. The demand reduction and energy efficiency standards by design result in reduced energy and demand that could adversely affect our results of operations, financial condition and cash flows.
The availability and cost of fuel has experienced and could continue to experience significant volatility and we may not be able to hedge the entire exposure of our operations from fuel availability and price volatility.
We purchase coal, natural gas and other fuel from a number of suppliers. The coal market in particular has experienced significant price volatility in the last several years. We are now in a global market for coal in which our domestic price is increasingly affected by international supply disruptions and demand balance. Coal exports from the U.S. have increased significantly at times in recent years. In addition, domestic issues like government-imposed direct costs and permitting issues that affect mining costs and supply availability, the variable demand of retail customer load and the performance of our generation fleet have an impact on our fuel procurement operations. Our approach is to hedge the fuel costs for our anticipated electric sales. However, we may not be able to hedge the entire exposure of our operations from fuel price volatility. As of June 30, 2012, DPL had substantially all of the total expected coal volume needed to meet its retail and firm wholesale sales requirements for 2012 under contract. In 2011, approximately 84% of DP&L’s coal was provided by four suppliers, three of which were under long-term contracts with DP&L. Historically, some of our suppliers and buyers of fuel have not performed on their contracts and have failed to deliver or accept fuel as specified under their contracts. To the extent our suppliers and buyers do not meet their contractual commitments and, as a result of such failure or otherwise, we cannot secure adequate fuel or sell excess fuel in a timely or cost-effective manner or we are not hedged against price volatility, we could have a material adverse effect on our results of operations, financial condition and cash flows. In addition, DP&L is a co-owner of certain generation facilities where it is a non-operating owner. DP&L does not procure or have control over the fuel for these facilities, but is responsible for its proportionate share of the cost of fuel procured at these facilities. Co-owner operated facilities do not always have realized fuel costs that are equal to our co-owners’ projections, and we are responsible for our proportionate share of any increase in actual fuel costs. Fuel and purchased power costs represent a large and volatile portion of DP&L’s total cost. Pursuant to its ESP for SSO retail customers, DP&L implemented a fuel and purchased power recovery mechanism beginning on January 1, 2010, which subjects our recovery of fuel and purchased power costs to tracking and adjustment on a seasonal quarterly basis. If in the future we are unable to timely or fully recover our fuel and purchased power costs, it could have a material adverse effect on our results of operations, financial condition and cash flows.
Our use of derivative and nonderivative contracts may not fully hedge our generation assets, customer supply activities, or other market positions against changes in commodity prices, and our hedging procedures may not work as planned.
We transact in coal, power and other commodities to hedge our positions in these commodities. These trades are impacted by a range of factors, including variations in power demand, fluctuations in market prices, market prices for alternative commodities and optimization opportunities. We have attempted to manage our commodities price risk exposure by establishing and enforcing risk limits and risk management policies. Despite our efforts, however, these risk limits and management policies may not work as planned and fluctuating prices and other events could adversely affect our results of operations, financial condition and cash flows. As part of our risk management, we use a variety of non-derivative and derivative instruments, such as swaps, futures and forwards, to manage our market risks. We also use interest rate derivative instruments to hedge against interest rate fluctuations related to our debt. In the absence of actively quoted market prices and pricing information from external sources, the valuation of some of these derivative instruments involves management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of
some of these contracts. We could also recognize financial losses as a result of volatility in the market values of these contracts or if a counterparty fails to perform, which could result in a material adverse effect on our results of operations, financial condition and cash flows.
The Dodd-Frank Act contains significant requirements related to derivatives that, among other things, could reduce the cost effectiveness of entering into derivative transactions.
In July 2010, The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was signed into law. The Dodd-Frank Act contains significant requirements relating to derivatives, including, among others, a requirement that certain transactions be cleared on exchanges that would necessitate the posting of cash collateral for these transactions. The Dodd-Frank Act provides a potential exception from these clearing and cash collateral requirements for commercial end-users. The Dodd-Frank Act requires the CFTC to establish rules to implement the Dodd-Frank Act’s requirements and exceptions. Requirements to post collateral could reduce the cost effectiveness of entering into derivative transactions to reduce commodity price and interest rate volatility or could increase the demands on our liquidity or require us to increase our levels of debt to enter into such derivative transactions. Even if we were to qualify for an exception from these requirements, our counterparties that do not qualify for the exception may pass along any increased costs incurred by them through higher prices and reductions in unsecured credit limits or be unable to enter into certain transactions with us. The occurrence of any of these events could have an adverse effect on our results of operations, financial condition and cash flows.
We are subject to numerous environmental laws and regulations that require capital expenditures, increase our cost of operations and may expose us to environmental liabilities.
Our operations and facilities (both wholly-owned and co-owned with others) are subject to numerous and extensive federal, state and local environmental laws and regulations relating to various matters, including air quality (such as reductions in NOx, SO2 and particulate matter emissions), water quality, wastewater discharge, solid waste and hazardous waste. We could also become subject to additional environmental laws and regulations and other requirements in the future (such as reductions in mercury and other hazardous air pollutants, SO3 (sulfur trioxide), regulation of ash generated from coal-based generating stations and reductions in greenhouse gas emissions as discussed in more detail in the next risk factor). With respect to our largest generation station, the J.M. Stuart Station, we are also subject to continuing compliance requirements related to NOx, SO2 and particulate matter emissions under DP&L’s consent decree with the Sierra Club. Compliance with these laws, regulations and other requirements requires us to expend significant funds and resources and could at some point become prohibitively expensive or result in our shutting down (temporarily or permanently) or altering the operation of our facilities. Environmental laws and regulations also generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. If we are not able to timely obtain, maintain or comply with all licenses, permits, inspections and approvals required to operate our business, then our operations could be prevented, delayed or subject to additional costs. Failure to comply with environmental laws, regulations and other requirements may result in the imposition of fines and penalties or other sanctions and the imposition of stricter environmental standards and controls and other injunctive measures affecting operating assets. In addition, any alleged violation of these laws, regulations and other requirements may require us to expend significant resources to defend against any such alleged violations. DP&L owns a non-controlling interest in several generating stations operated by our co-owners. As a non-controlling owner in these generating stations, DP&L is responsible for its pro rata share of expenditures for complying with environmental laws, regulations and other requirements, but has limited control over the compliance measures taken by our co-owners. DP&L has an EIR in place as part of its existing rate plan structure, the last increase of which occurred in 2010 and remains at that level through 2012. In addition, DP&L’s ESP permits it to seek recovery for costs associated with new climate change or carbon regulations. While we expect to recover certain environmental costs and expenditures from customers, if in the future we are unable to fully recover our costs in a timely manner or the SSO retail riders are bypassable or additional customer switching occurs, we could have a material adverse effect to our results of operations, financial condition and cash flows. In addition, if we were found not to be in compliance with these environmental laws, regulations or requirements, any penalties that would apply or other resulting costs would likely not be recoverable from customers. We could be subject to joint and several strict liability for any environmental contamination at our currently or formerly owned, leased or operated properties or third-party waste disposal sites. For example, contamination has been identified at two waste disposal sites for which we are alleged to have potential liability. In
addition to potentially significant investigation and remediation costs, any such contamination matters can give rise to claims from governmental authorities and other third parties for fines or penalties, natural resource damages, personal injury and property damage.
Our costs and liabilities relating to environmental matters could have a material adverse effect on our results of operations, financial condition and cash flows.
If legislation or regulations at the federal, state or regional levels impose mandatory reductions of greenhouse gases on generation facilities, we could be required to make large additional capital investments and incur substantial costs.
There is an ongoing concern nationally and internationally among regulators, investors and others concerning global climate change and the contribution of emissions of GHGs, including most significantly CO2. This concern has led to interest in legislation and action at the international, federal, state and regional levels and litigation, including regulation of GHG emissions by the USEPA. Approximately 98% of the energy we produce is generated by coal. As a result of current or future legislation or regulations at the international, federal, state or regional levels imposing mandatory reductions of CO2 and other GHGs on generation facilities, we could be required to make large additional capital investments and/or incur substantial costs in the form of taxes or emissions allowances. Such legislation and regulations could also impair the value of our generation stations or make some of these stations uneconomical to maintain or operate and could raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing generation stations. Although DP&L is permitted under its current ESP to seek recovery of costs associated with new climate change or carbon regulations, our inability to fully or timely recover such costs could have a material adverse effect on our results of operations, financial condition and cash flows.
Fluctuations in our sales of coal and excess emission allowances could cause a material adverse effect on our results of operations, financial condition and cash flows for any particular period.
DP&L sells coal to other parties from time to time for reasons that include maintaining an appropriate balance between projected supply and projected use and as part of a coal price optimization program where coal under contract may be resold and replaced with other coal or power available in the market with a favorable price spread, adjusted for any quality differentials. During 2010 and 2009, DP&L realized net gains from these sales. Sales of coal are affected by a range of factors, including price volatility among the different coal basins and qualities of coal, variations in power demand and the market price of power compared to the cost to produce power. These factors could cause the amount and price of coal we sell to fluctuate, which could cause a material adverse effect on our results of operations, financial condition and cash flows for any particular period.
DP&L may sell its excess emission allowances, including NOx and SO2 emission allowances from time to time. Sales of any excess emission allowances are affected by a range of factors, such as general economic conditions, fluctuations in market demand, availability of excess inventory available for sale and changes to the regulatory environment, including with respect to CSAPR and CAIR. These factors could cause the amount and price of excess emission allowances DP&L sells to fluctuate, which could cause a material adverse effect on DPL’s results of operations, financial condition and cash flows for any particular period. Although there has been overall reduced trading activity in the annual NOx and SO2 emission allowance trading markets in recent years, the adoption of regulations that regulate emissions or establish or modify emission allowance trading programs could affect the emission allowance trading markets and have a material effect on DP&L’s emission allowance sales.
The operation and performance of our facilities are subject to various events and risks that could negatively affect our business.
The operation and performance of our generation, transmission and distribution facilities and equipment is subject to various events and risks, such as the potential breakdown or failure of equipment, processes or facilities, fuel supply or transportation disruptions, the loss of cost-effective disposal options for solid waste generated by our facilities (such as coal ash and gypsum), accidents, injuries, labor disputes or work stoppages by employees, operator error, acts of terrorism or sabotage, construction delays or cost overruns, shortages of or delays in obtaining equipment, material and labor, operational restrictions resulting from environmental limitations and governmental
interventions, performance below expected or required levels, weather-related and other natural disruptions, vandalism, events occurring on the systems of third parties that interconnect to and affect our system and the increased maintenance requirements, costs and risks associated with our aging generation units. Our results of operations, financial condition and cash flows could have a material adverse effect due to the occurrence or continuation of these events.
Diminished availability or performance of our transmission and distribution facilities could result in reduced customer satisfaction and regulatory inquiries and fines, which could have a material adverse effect on our results of operations, financial condition and cash flows. Operation of our owned and co-owned generating stations below expected capacity levels, or unplanned outages at these stations, could cause reduced energy output and efficiency levels and likely result in lost revenues and increased expenses that could have a material adverse effect on our results of operations, financial condition and cash flows. In particular, since over 50% of our base-load generation is derived from co-owned generation stations operated by our co-owners, poor operational performance by our co-owners, misalignment of co-owners’ interests or lack of control over costs (such as fuel costs) incurred at these stations could have an adverse effect on us. We have constructed and placed into service FGD facilities at most of our base-load generating stations. If there is significant operational failure of the FGD equipment at the generating stations, we may not be able to meet emission requirements at some of our generating stations or, at other stations, it may require us to burn more expensive types of coal or utilize emission allowances. These events could result in a substantial increase in our operating costs. Depending on the degree, nature, extent, or willfulness of any failure to comply with environmental requirements, including those imposed by any consent decrees, such non-compliance could result in the imposition of penalties or the shutting down of the affected generating stations, which could have a material adverse effect on our results of operations, financial condition and cash flows.
Asbestos and other regulated substances are, and may continue to be, present at our facilities. We have been named as a defendant in asbestos litigation, which at this time is not material to us. The continued presence of asbestos and other regulated substances at these facilities could result in additional litigation being brought against us, which could have a material adverse effect on our results of operations, financial condition and cash flows.
If we were found not to be in compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties, which likely would not be recoverable from customers through regulated rates and could have a material adverse effect on our results of operations, financial condition and cash flows.
As an owner and operator of a bulk power transmission system, DP&L is subject to mandatory reliability standards promulgated by the NERC and enforced by the FERC. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and is guided by reliability and market interface principles. In addition, DP&L is subject to Ohio reliability standards and targets. Compliance with reliability standards subjects us to higher operating costs or increased capital expenditures. While we expect to recover costs and expenditures from customers through regulated rates, there can be no assurance that the PUCO will approve full recovery in a timely manner. If we were found not to be in compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties, which likely would not be recoverable from customers through regulated rates and could have a material adverse effect on our results of operations, financial condition and cash flows.
Our financial results may fluctuate on a seasonal and quarterly basis or as a result of severe weather.
Weather conditions significantly affect the demand for electric power. In our Ohio service territory, demand for electricity is generally greater in the summer months associated with cooling and in the winter months associated with heating as compared to other times of the year. Unusually mild summers and winters could therefore have an adverse effect on our results of operations, financial condition and cash flows. In addition, severe or unusual weather, such as hurricanes and ice or snow storms, may cause outages and property damage that may require us to incur additional costs that may not be insured or recoverable from customers. While DP&L is permitted to seek recovery of storm damage costs under its ESP, if DP&L is unable to fully recover such costs in a timely manner, it could have a material adverse effect on our results of operations, financial condition and cash flows.
Our membership in a regional transmission organization presents risks that could have a material adverse effect on our results of operations, financial condition and cash flows.
On October 1, 2004, in compliance with Ohio law, DP&L turned over control of its transmission functions and fully integrated into PJM, a regional transmission organization. The price at which we can sell our generation capacity and energy is now dependent on a number of factors, which include the overall supply and demand of generation and load, other state legislation or regulation, transmission congestion and PJM’s business rules. While we can continue to make bilateral transactions to sell our generation through a willing-buyer and willing-seller relationship, any transactions that are not pre-arranged are subject to market conditions at PJM. To the extent we sell electricity into the power markets on a contractual basis, we are not guaranteed any rate of return on our capital investments through mandated rates. The results of the PJM RPM base residual auction are impacted by the supply and demand of generation and load and also may be impacted by congestion and PJM rules relating to bidding for Demand Response and Energy Efficiency resources and other factors. Auction prices could fluctuate substantially over relatively short periods of time and adversely affect our results of operations, financial condition and cash flows. We cannot predict the outcome of future auctions, but if auction prices are at low levels, our results of operations, financial condition and cash flows could have a material adverse effect.
The rules governing the various regional power markets may also change from time to time which could affect our costs and revenues and have a material adverse effect on our results of operations, financial condition and cash flows. We may be required to expand our transmission system according to decisions made by PJM rather than our internal planning process. While PJM transmission rates were initially designed to be revenue neutral, various proposals and proceedings currently taking place at FERC may cause transmission rates to change from time to time. In addition, PJM has been developing rules associated with the allocation and methodology of assigning costs associated with improved transmission reliability, reduced transmission congestion and firm transmission rights that may have a financial effect on us. We also incur fees and costs to participate in PJM.
SB 221 includes a provision that allows electric utilities to seek and obtain recovery of RTO related charges. Therefore, most if not all of the above costs are currently being recovered through our SSO retail rates. If in the future, however, we are unable to recover all of these costs in a timely manner, or the SSO retail riders are bypassable or additional customer switching occurs, our results of operations, financial condition and cash flows could have a material adverse effect.
As members of PJM, DP&L and DPLE are also subject to certain additional risks including those associated with the allocation among PJM members of losses caused by unreimbursed defaults of other participants in PJM markets and those associated with complaint cases filed against PJM that may seek refunds of revenues previously earned by PJM members including DP&L and DPLE. These amounts could be significant and have a material adverse effect on our results of operations, financial condition and cash flows.
Costs associated with new transmission projects could have a material adverse effect on our results of operations, financial condition and cash flows.
Annually, PJM performs a review of the capital additions required to provide reliable electric transmission services throughout its territory. PJM traditionally allocated the costs of constructing these facilities to those entities that benefited directly from the additions. FERC orders issued in 2007 and thereafter modified the traditional method of allocating costs associated with new high-voltage planned transmission facilities. FERC ordered that the cost of new high-voltage facilities be socialized across the PJM region. Various parties, including DP&L, challenged this allocation method and in 2009, the U.S. Court of Appeals, Seventh Circuit ruled that the FERC had failed to provide a reasoned basis for the allocation method and remanded the case to the FERC for further proceedings. Until such time as FERC may act to approve a change in methodology, PJM will continue to apply the allocation methodology that had been approved by FERC in 2007. The overall impact of FERC’s allocation methodology cannot be definitively assessed because not all new planned construction is likely to happen. To date, the additional costs charged to DP&L for new large transmission approved projects has not been material. Over time, as more new transmission projects are constructed and if the allocation method is not changed, the annual costs could become material. Although we continue to maintain that the costs of these projects should be borne by the direct beneficiaries of the projects and that DP&L is not one of these beneficiaries, DP&L is recovering the Ohio retail jurisdictional share of these allocated costs from its SSO retail customers through the TCRR rider. To the
extent that any costs in the future are material and we are unable to recover them from our customers, it could have a material adverse effect on our results of operation, financial condition and cash flows.
Our inability to obtain financing on reasonable terms, or at all, with creditworthy counterparties could adversely affect our results of operations, financial condition and cash flows.
From time to time we rely on access to the credit and capital markets to fund certain of our operational and capital costs. These capital and credit markets have experienced extreme volatility and disruption and the ability of corporations to obtain funds through the issuance of debt or equity has been negatively impacted. Disruptions in the credit and capital markets make it harder and more expensive to obtain funding for our business. Access to funds under our existing financing arrangements is also dependent on the ability of our counterparties to meet their financing commitments. Our inability to obtain financing on reasonable terms, or at all, with creditworthy counterparties could adversely affect our results of operations, financial condition and cash flows. If our available funding is limited or we are forced to fund our operations at a higher cost, these conditions may require us to curtail our business activities and increase our cost of funding, both of which could reduce our profitability. DP&L has variable rate debt that bears interest based on a prevailing rate that is reset weekly based on a market index that can be affected by market demand, supply, market interest rates and other market conditions. We also currently maintain both cash on deposit and investments in cash equivalents that could be adversely affected by interest rate fluctuations. In addition, ratings agencies issue credit ratings on us and our debt that affect our borrowing costs under our financial arrangements and affect our potential pool of investors and funding sources. Our credit ratings also govern the collateral provisions of certain of our contracts. As a result of the Merger (as defined below) and assumption by DPL of Merger-related debt, our credit ratings were downgraded, resulting in increased borrowing costs and causing us to post cash collateral with certain of our counterparties. If the rating agencies were to downgrade our credit ratings further, our borrowing costs would likely further increase, our potential pool of investors and funding resources could be reduced, and we could be required to post additional cash collateral under selected contracts. These events would likely reduce our liquidity and profitability and could have a material adverse effect on our results of operations, financial condition and cash flows.
Poor investment performance of our benefit plan assets and other factors impacting benefit plan costs could unfavorably affect our liquidity and results of operations.
The performance of the capital markets affects the values of the assets that are held in trust to satisfy future obligations under our pension and postretirement benefit plans. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected return rates. A decline in the market value of the pension and postretirement benefit plan assets will increase the funding requirements under our pension and postretirement benefit plans if the actual asset returns do not recover these declines in value in the foreseeable future. Future pension funding requirements, and the timing of funding payments, may also be subject to changes in legislation. The Pension Protection Act, enacted in August 2006, requires underfunded pension plans to improve their funding ratios within prescribed intervals based on the level of their underfunding. As a result, our required contributions to these plans at times have increased and may increase in the future. In addition, our pension and postretirement benefit plan liabilities are sensitive to changes in interest rates. As interest rates decrease, the discounted liabilities increase benefit expense and funding requirements. Further, changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions, may also increase the funding requirements for the obligations related to the pension and other postretirement benefit plans. Declines in market values and increased funding requirements could have a material adverse effect on our results of operations, financial condition and cash flows.
Our businesses depend on counterparties performing in accordance with their agreements. If they fail to perform, we could incur substantial expense, which could adversely affect our liquidity, cash flows and results of operations.
We enter into transactions with and rely on many counterparties in connection with our business, including for the purchase and delivery of inventory, including fuel and equipment components (such as limestone for our FGD equipment), for our capital improvements and additions and to provide professional services, such as actuarial calculations, payroll processing and various consulting services. If any of these counterparties fails to perform its obligations to us or becomes unavailable, our business plans may be materially disrupted, we may be forced to
discontinue certain operations if a cost-effective alternative is not readily available or we may be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices and cause delays. These events could cause our results of operations, financial condition and cash flows to be materially adversely effected.
Our consolidated results of operations may be negatively affected by overall market, economic and other conditions that are beyond our control.
Economic pressures, as well as changing market conditions and other factors related to physical energy and financial trading activities, which include price, credit, liquidity, volatility, capacity, transmission and interest rates, can have a significant effect on our operations and the operations of our retail, industrial and commercial customers and our suppliers. The direction and relative strength of the economy has been increasingly uncertain due to softness in the real estate and mortgage markets, volatility in fuel and other energy costs, difficulties in the financial services sector and credit markets, high unemployment and other factors. Many of these factors have affected our Ohio service territory.
Our results of operations, financial condition and cash flows may be negatively affected by sustained downturns or a sluggish economy. Sustained downturns, recessions or a sluggish economy generally affect the markets in which we operate and negatively influence our energy operations. A contracting, slow or sluggish economy could reduce the demand for energy in areas in which we are doing business. During economic downturns, our commercial and industrial customers may see a decrease in demand for their products, which in turn may lead to a decrease in the amount of energy they require. In addition, our customers’ ability to pay us could also be impaired, which could result in an increase in receivables and write-offs of uncollectible accounts. Our suppliers could also be affected by the economic downturn resulting in supply delays or unavailability. Reduced demand for our electric services, failure by our customers to timely remit full payment owed to us and supply delays or unavailability could have a material adverse effect on our results of operations, financial condition and cash flows.
Accidental improprieties and undetected errors in our internal controls and information reporting could result in the disallowance of cost recovery, noncompliant disclosure and reporting or incorrect payment processing.
Our internal controls, accounting policies and practices and internal information systems are designed to enable us to capture and process transactions and information in a timely and accurate manner in compliance with GAAP in the United States of America, laws and regulations, taxation requirements and federal securities laws and regulations in order to, among other things, disclose and report financial and other information in connection with the recovery of our costs and with our reporting requirements under federal securities, tax and other laws and regulations and to properly process payments. We have also implemented corporate governance, internal control and accounting policies and procedures in connection with the Sarbanes-Oxley Act of 2002. Our internal controls and policies have been and continue to be closely monitored by management and our Board of Directors. While we believe these controls, policies, practices and systems are adequate to verify data integrity, unanticipated and unauthorized actions of employees, temporary lapses in internal controls due to shortfalls in oversight or resource constraints could lead to improprieties and undetected errors that could result in the disallowance of cost recovery, noncompliant disclosure and reporting or incorrect payment processing. The consequences of these events could have a material adverse effect on our results of operations, financial condition and cash flows.
New accounting standards or changes to existing accounting standards could materially affect how we report our results of operations, financial condition and cash flows.
Our Consolidated Financial Statements are prepared in accordance with accounting principles generally accepted in the United States of America. The SEC, FASB or other authoritative bodies or governmental entities may issue new pronouncements or new interpretations of existing accounting standards that may require us to change our accounting policies. These changes are beyond our control, can be difficult to predict and could materially affect how we report our results of operations, financial condition and cash flows. We could be required to apply a new or revised standard retroactively, which could adversely affect our financial condition. In addition, in preparing our Consolidated Financial Statements, management is required to make estimates and assumptions. Actual results could differ significantly from those estimates.
The SEC is investigating the potential transition to the use of International Financial Reporting Standards (IFRS) promulgated by the International Accounting Standards Board for U.S. companies. Adoption of IFRS could result in significant changes to our accounting and reporting, such as in the treatment of regulatory assets and liabilities and property. The SEC does not currently have a timeline regarding the mandatory adoption of IFRS. We are currently assessing the effect that this potential change would have on our Consolidated Financial Statements and we will continue to monitor the development of the potential implementation of IFRS.
If we are unable to maintain a qualified and properly motivated workforce, our results of operations, financial condition and cash flows could have a material adverse effect.
One of the challenges we face is to retain a skilled, efficient and cost-effective workforce while recruiting new talent to replace losses in knowledge and skills due to retirements. This undertaking could require us to make additional financial commitments and incur increased costs. If we are unable to successfully attract and retain an appropriately qualified workforce, our results of operations, financial condition and cash flows could have a material adverse effect. In addition, we have employee compensation plans that reward the performance of our employees. We seek to ensure that our compensation plans encourage acceptable levels for risk and high performance through pay mix, performance metrics and timing. We also have policies and procedures in place to mitigate excessive risk-taking by employees since excessive risk-taking by our employees to achieve performance targets could result in events that could have a material adverse effect on our results of operations, financial condition and cash flows.
We are subject to collective bargaining agreements and other employee workforce factors that could affect our businesses.
Over half of our employees are represented by a collective bargaining agreement that is in effect until October 31, 2014. While we believe that we maintain a satisfactory relationship with our employees, it is possible that labor disruptions affecting some or all of our operations could occur during the period of the collective bargaining agreement or at the expiration of the collective bargaining agreement before a new agreement is negotiated. Work stoppages by, or poor relations or ineffective negotiations with, our employees could have a material adverse effect on our results of operations, financial condition and cash flows.
Potential security breaches (including cybersecurity breaches) and terrorism risks could adversely affect our business.
We operate in a highly regulated industry that requires the continued operation of sophisticated systems and network infrastructure at our generation plants, fuel storage facilities, transmission and distribution facilities. We also use various financial, accounting and other systems in our businesses. These systems and facilities are vulnerable to unauthorized access due to hacking, viruses, other cybersecurity attacks and other causes. In particular, given the importance of energy and the electric grid, there is the possibility that our systems and facilities could be targets of terrorism or acts of war. We have implemented measures to help prevent unauthorized access to our systems and facilities, including certain measures to comply with mandatory regulatory reliability standards. Despite our efforts, if our systems or facilities were to be breached or disabled, we may be unable to recover them in a timely way to fulfill critical business functions, including the supply of electric services to our customers, and we could experience decreases in revenues and increases in costs that could adversely affect our results of operations, cash flows and financial condition.
In the course of our business, we also store and use customer, employee, and other personal information and other confidential and sensitive information. If DPL’s or our third party vendors’ systems were to be breached or disabled, sensitive and confidential information and other data could be compromised, which could result in negative publicity, remediation costs and potential litigation, damages, consent orders, injunctions, fines and other relief.
To help mitigate against these risks, we maintain insurance coverage against some, but not all, potential losses, including coverage for illegal acts against us. However, insurance may not be adequate to protect us against all costs and liabilities associated with these risks.
DPL is a holding company and parent of DP&L and other subsidiaries. Our cash flow is dependent on the operating cash flows of DP&L and our other subsidiaries and their ability to pay cash to DPL.
DPL is a holding company and its investments in its subsidiaries are its primary assets. A significant portion of DPL’s business is conducted by its DP&L subsidiary. As such, DPL’s cash flow is dependent on the operating cash flows of DP&L and its ability to pay cash to DPL. DP&L’s governing documents contain certain limitations on the ability to declare and pay dividends to DPL while preferred stock is outstanding. Certain of DP&L’s debt agreements also contain limits with respect to the ability of DP&L to incur debt. In addition, DP&L is regulated by the PUCO, which possesses broad oversight powers to ensure that the needs of utility customers are being met. As a part of a stipulation approving the Merger (as defined below) of DPL into AES, DPL agreed to restrictions that could limit dividends DP&L makes to DPL. As part of the PUCO’s approval of the Merger, DP&L agreed to maintain a capital structure that includes an equity ratio of at least 50 percent and not to have a negative retained earnings balance. While we do not expect any of the foregoing restrictions to significantly affect DP&L’s ability to pay funds to DPL in the future, a significant limitation on DP&L’s ability to pay dividends or loan or advance funds to DPL would have a material adverse effect on DPL’s results of operations, financial condition and cash flows.
We will be subject to business uncertainties during the integration process with respect to the Merger with The AES Corporation that could adversely affect our financial results.
On November 28, 2011, DPL merged with Dolphin Sub, Inc., a wholly owned subsidiary of AES pursuant to the Agreement and Plan of Merger (the “Merger Agreement”) whereby AES acquired DPL for $30.00 per share in a cash transaction valued at approximately $3.5 billion (the “Merger”). At closing, DPL became a wholly owned subsidiary of AES. Uncertainty about the effect of the Merger on DPL and DP&L, their employees, customers and suppliers may have an adverse effect on us. Although we intend to take steps designed to reduce any adverse effects, these uncertainties could cause customers, suppliers and others that deal with us to seek to change existing business relationships.
The success of our business will depend on DPL’s and DP&L’s ability to realize anticipated benefits from the integration into AES. Certain risks to achieving these benefits include:
· | the ability to successfully integrate into AES; |
· | ongoing operating performance; |
· | the adaptability to changes resulting from the Merger; and |
· | continued employee retention and recruitment after the Merger. |
We expect that matters relating to the Merger and integration-related issues will place a significant burden on management, employees and internal resources, which could otherwise have been devoted to other business opportunities. The diversion of management time on Merger integration-related issues could affect our financial results.
Push-down accounting adjustments in connection with the Merger may have a material effect on DPL’s future financial results.
Under U.S. GAAP, pursuant to FASC No. 805 and SEC Staff Accounting Bulletin Topic 5.J. “New Basis of Accounting Required in Certain Circumstances”, when an acquisition results in an entity becoming substantially wholly-owned, push-down accounting is applied in the acquired entity’s separate financial statements. Push-down accounting requires that the fair value adjustments and goodwill or negative goodwill identified by the acquiring entity be pushed down and reflected in the financial statements of the acquired entity. As a result, following the completion by AES of its purchase price allocation in connection with the Merger, the cost basis of certain of DPL’s assets and liabilities has been and will continue to be adjusted and any resulting goodwill will be allocated and pushed down to DPL. Although initial adjustments were made in the second quarter of 2012, AES is still in the process of reviewing the adjustments, which are based on purchase price allocations and valuations of DPL’s assets and liabilities. Additional adjustments could have a material effect on DPL’s future financial condition and results
of operations, including but not limited to increased depreciation, amortization, impairment and other non-cash charges. As a result, DPL’s actual future results may not be comparable with results in prior periods.
Impairment of goodwill or long-lived assets would negatively affect our consolidated results of operations and net worth.
Goodwill represents the future economic benefits arising from assets acquired in a business combination (acquisition) that are not individually identified and separately recognized. Goodwill is not amortized, but is evaluated for impairment at least annually or more frequently if impairment indicators are present. In evaluating the potential impairment of goodwill, we make estimates and assumptions about revenue, operating cash flows, capital expenditures, growth rates and discount rates based on our budgets and long term forecasts, macroeconomic projections, and current market expectations of returns on similar assets. There are inherent uncertainties related to these factors and management’s judgment in applying these factors. Generally, the fair value of a reporting unit is determined using a discounted cash flow valuation model. We could be required to evaluate the potential impairment of goodwill outside of the required annual assessment process if we experience situations, including but not limited to: deterioration in general economic conditions, operating or regulatory environment; increased competitive environment; increase in fuel costs particularly when we are unable to pass along such costs to customers; negative or declining cash flows; loss of a key contract or customer particularly when we are unable to replace it on equally favorable terms; or adverse actions or assessments by a regulator. These types of events and the resulting analyses could result in goodwill impairment expense, which could substantially affect our results of operations for those periods. As a result of the push-down of purchase accounting to DPL from the acquisition of DPL by AES in November 2011, we had $2.6 billion of goodwill at June 30, 2012, which represented approximately 42% of total assets.
Long-lived assets are initially recorded at fair value when acquired in a business combination and are amortized or depreciated over their estimated useful lives. Long-lived assets are evaluated for impairment only when impairment indicators are present whereas goodwill is evaluated for impairment on an annual basis or more frequently if potential impairment indicators are present. Otherwise, the recoverability assessment of long-lived assets is similar to the potential impairment evaluation of goodwill particularly as it relates to the identification of potential impairment indicators, and making estimates and assumptions to determine fair value, as described above.
This prospectus includes certain “forward-looking statements” that involve many risks and uncertainties. Forward-looking statements express an expectation or belief and contain a projection, plan or assumption with regard to, among other things, our future revenues, income, expenses or capital structure. Such statements of future events or performance are not guarantees of future performance and involve estimates, assumptions and uncertainties. The words “could,” “may,” “predict,” “anticipate,” “would,” “believe,” “estimate,” “expect,” “forecast,” “project,” “objective,” “intend,” “continue,” “should,” “plan,” and similar expressions, or the negatives thereof, are intended to identify forward-looking statements unless the context requires otherwise. These forward-looking statements are based on management’s present expectations and beliefs about future events. As with any projection or forecast, these statements are inherently susceptible to uncertainty and changes in circumstances. We are under no obligation to, and expressly disclaim any obligation to, update or alter the forward-looking statements whether as a result of such changes, new information, subsequent events or otherwise. If we do update one or more forward-looking statements, no inference should be made that we will make additional updates with respect to those or other forward-looking statements.
Important factors that could cause actual results to differ materially from those reflected in such forward-looking statements and that should be considered in evaluating our outlook include, but are not limited to, the following:
· | abnormal or severe weather and catastrophic weather-related damage; |
· | unusual maintenance or repair requirements; |
· | changes in fuel costs and purchased power, coal, environmental emissions, natural gas and other commodity prices; |
· | volatility and changes in markets for electricity and other energy-related commodities; |
· | performance of our suppliers; |
· | increased competition and deregulation in the electric utility industry; |
· | increased competition in the retail generation market; |
· | changes in interest rates; |
· | state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, emission levels, rate structures or tax laws; |
· | changes in environmental laws and regulations to which we and our subsidiaries are subject; |
· | the development and operation of RTOs, including PJM to which DP&L has given control of its transmission functions; |
· | changes in our purchasing processes, pricing, delays, contractor and supplier performance and availability; |
· | significant delays associated with large construction projects; |
· | growth in our service territory and changes in demand and demographic patterns; |
· | changes in accounting rules and the effect of accounting pronouncements issued periodically by accounting standard-setting bodies; |
· | financial market conditions; |
· | the outcomes of litigation and regulatory investigations, proceedings or inquiries; |
· | costs related to the Merger and the effects of any disruption from the Merger that may make it more difficult to maintain relationships with employees, customers, other business partners or government entities; and |
· | general economic conditions. |
All such factors are difficult to predict, contain uncertainties that may materially affect actual results, and many are beyond our control. See “Risk Factors” for a more detailed discussion of the foregoing and certain other factors that could cause actual results to differ materially from those reflected in such forward-looking statements and that should be considered in evaluating our outlook.
We will not receive any cash proceeds from the issuance of the new notes. The new notes will be exchanged for old notes as described in this prospectus upon our receipt of old notes. We will cancel all of the old notes surrendered in exchange for the new notes.
Our net proceeds from the sale of the old notes were approximately $1,234 million, after deduction of the initial purchasers’ discounts and commissions and other expenses of the offering. The proceeds from the offering were used to partially finance the acquisition of DPL by AES, which was consummated in November 2011, and to pay related fees and expenses.
The following table presents our ratio of earnings to fixed charges for the periods indicated:
Year Ended December 31, | ||||||||||||||||||||||||
Six Months Ended June 30, 2012 | 2011 | 2010 | 2009 | 2008 | 2007 | |||||||||||||||||||
Ratio of earnings to fixed charges | 1.85 | 3.82 | 6.99 | 5.00 | 4.49 | 4.35 |
The Ratio of Earnings to Fixed Charges represents, on a pre-tax basis, the number of times earnings cover fixed charges. Earnings consist of earnings before income tax expense and fixed charges. Fixed charges consist of interest on long term-debt, other interest expense and an estimate of the interest portion of all rentals charged to income.
The following table sets forth a summary of our consolidated capitalization as of June 30, 2012:
This table should be read in conjunction with “Management’s Discussion and Analysis of Results of Operations and Financial Condition” and the financial statements and related notes included herein.
As of June 30, 2012 | ||||
(in millions) | ||||
Current portion of long-term debt | $ | 0.4 | ||
Long-term debt(1): | ||||
5.125% first mortgage bonds due 2013 | 494.0 | |||
4.70% pollution control bonds due 2028 | 36.1 | |||
4.80% pollution control bonds due 2034 | 179.6 | |||
4.80% pollution control bonds due 2036 | 96.2 | |||
Variable rate pollution control bonds due 2040 | 100.0 | |||
U.S. Government note due 2061 | 18.4 | |||
8.125% Note to DPL Capital Trust II due 2031 | 19.7 | |||
6.50% senior notes due 2016 | 450.0 | |||
7.25% senior notes due 2021 | 800.0 | |||
Variable rate bank term loan | 425.0 | |||
Unamortized debt discounts | — | |||
Obligations for capital leases | 0.2 | |||
Total long-term debt | 2,619.6 | |||
Redeemable preferred stock of subsidiary | 18.4 | |||
Shareholders’ equity | 2,187.3 | |||
Total capitalization | $ | 4,825.3 |
(1) | Debt amounts are shown at carrying value, which reflects the estimated fair value at the Merger date adjusted for subsequent amortization of premiums and discounts. |
The table below presents our selected historical consolidated financial and other data for the periods presented, which should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and related notes included herein.
The selected historical consolidated statement of operations and other operating data for each of the years ended December 31, 2011, 2010 and 2009 are derived from our audited consolidated financial statements included herein. The selected historical statement of operations and other operating data for each of the years ended December 31, 2008 and 2007 are derived from our audited consolidated financial statements not included herein. The selected historical consolidated statement of operations and other operating data for each of the six months ended June 30, 2012 and 2011 are derived from our unaudited condensed consolidated financial statements included herein. The unaudited condensed consolidated financial statements have been prepared on the same basis as the audited consolidated financial statements and, in the opinion of management, include all adjustments, consisting only of normal recurring adjustments, necessary to present fairly the data for the period. Our historical results for any prior period are not necessarily indicative of results to be expected for any future period.
Successor(a) | Predecessor(a) | |||||||||||||||||||||||||||||||
Six Months Ended June 30, | November 28, 2011 through December 31, 2011 | January 1, 2011 through November 27, 2011 | Years Ended December 31, | |||||||||||||||||||||||||||||
Successor(a) | Predecessor(a) | |||||||||||||||||||||||||||||||
Statement of Operations Data: | 2012 | 2011 | 2010 | 2009 | 2008 | 2007 | ||||||||||||||||||||||||||
($ in millions) | ||||||||||||||||||||||||||||||||
Revenues | $ | 816.0 | $ | 913.9 | $ | 156.9 | $ | 1,670.9 | $ | 1,831.4 | $ | 1,539.4 | $ | 1,549.2 | $ | 1,462.5 | ||||||||||||||||
Earnings from continued operations, net of tax | 33.6 | 75.2 | (6.2 | ) | 150.5 | 290.3 | 229.1 | 244.5 | 211.8 | |||||||||||||||||||||||
Net income | $ | 33.6 | $ | 75.2 | $ | (6.2 | ) | $ | 150.5 | $ | 290.3 | $ | 229.1 | $ | 244.5 | $ | 221.8 | |||||||||||||||
Other Operating Data: | 2012 | 2011 | 2011 | 2011 | 2010 | 2009 | 2008 | 2007 | ||||||||||||||||||||||||
Total electric sales (millions of kWh) | 7,251 | 8,114 | 1,361 | 15,021 | 17,237 | 16,667 | 17,172 | 18,598 |
(a) | “Predecessor” refers to the operations of DPL and its subsidiaries prior to the consummation of the Merger on November 28, 2011. “Successor” refers to the operations of DPL and its subsidiaries subsequent to the Merger. |
Balance Sheet Data: | As of June 30, 2012 | |||
($ in millions) | ||||
Cash and cash equivalents | $ | 152.3 | ||
Total assets | $ | 6,008.8 | ||
Long-term debt (excluding current portion) | $ | 2,619.2 | ||
Redeemable preferred stock of subsidiary | $ | 18.4 |
The following discussion and analysis should be read in conjunction with the financial statements and notes thereto included elsewhere in this prospectus. The following discussion contains forward-looking statements. Our actual results may differ materially from the results suggested by these forward-looking statements. Please see “Cautionary Note Regarding Forward Looking Statements” and “Risk Factors” in this prospectus.
Business Overview
DPL is a regional electric energy and utility company. DPL’s two reporting segments are the Utility segment, comprised of its DP&L subsidiary, and the Competitive Retail segment, comprised of its DPLER subsidiary and DPLER’s subsidiary, MC Squared Energy Services, LLC. Refer to Note 19 of Notes to DPL’s Consolidated Financial Statements and Note 14 of Notes to DPL’s Condensed Consolidated Financial Statements for more information relating to these reportable segments. DP&L does not have any reportable segments.
DP&L is primarily engaged in the generation, transmission and distribution of electricity in West Central Ohio. DPL and DP&L strive to achieve disciplined growth in energy margins while limiting volatility in both cash flows and earnings and to achieve stable, long-term growth through efficient operations and strong customer and regulatory relations. More specifically, DPL’s and DP&L’s strategy is to match energy supply with load or customer demand, maximizing profits while effectively managing exposure to movements in energy and fuel prices and utilizing the transmission and distribution assets that transfer electricity at the most efficient cost while maintaining the highest level of customer service and reliability.
We operate and manage generation assets and are exposed to a number of risks. These risks include, but are not limited to, electricity wholesale price risk, PJM capacity price risk, regulatory risk, environmental risk, fuel supply and price risk, customer switching risk and the risk associated with power plant performance. We attempt to manage these risks through various means. For instance, we operate a portfolio of wholly-owned and jointly-owned generation assets that is diversified as to coal source, cost structure and operating characteristics. We are focused on the operating efficiency of these power plants and maintaining their availability.
We operate and manage transmission and distribution assets in a rate-regulated environment. Accordingly, this subjects us to regulatory risk in terms of the costs that we may recover and the investment returns that we may collect in customer rates. We are focused on delivering electricity and maintaining high standards of customer service and reliability in a cost-effective manner.
Additional information relating to risks of our business is contained in “Risk Factors.”
The following discussion should be read in conjunction with the financial statements and related notes included elsewhere in this prospectus.
Business Combination
Acquisition by The AES Corporation
On November 28, 2011, DPL merged with Dolphin Sub, Inc., a wholly owned subsidiary of The AES Corporation, a Delaware corporation (“AES”) pursuant to the Merger Agreement whereby AES acquired DPL for $30.00 per share in a cash transaction valued at approximately $3.5 billion. At closing, DPL became a wholly owned subsidiary of AES.
Dolphin Subsidiary II, Inc., a subsidiary of AES, issued $1,250.0 million in long-term Senior Notes on October 3, 2011, to partially finance the Merger (see Note 2 of Notes to DPL’s Condensed Consolidated Financial Statements). Upon the consummation of the Merger, Dolphin Subsidiary II, Inc. was merged into DPL and these notes became long-term debt obligations of DPL. This debt has and will have a material effect on DPL’s cash requirements.
As a result of the Merger, including the assumption of merger-related debt, DPL and DP&L were downgraded by all three major credit rating agencies. We do not anticipate that these downgraded ratings will have a significant effect on our liquidity; however, we expect that our cost of capital will increase. See Note 6 of Notes to DPL’s Condensed Consolidated Financial Statements for more information.
DPL incurred merger transaction costs consisting primarily of banker’s fees, legal fees and change of control costs of approximately $53.6 million pre-tax during 2011 and an additional $1.0 million pre-tax during 2012. Other than these costs, interest on the additional debt and other items noted above, DPL and DP&L do not expect the Merger to have a significant effect on their financial position, results of operations or sources of liquidity during 2012.
The Merger also resulted in DPL recording $2,568.1 million in goodwill due to the push down of purchase accounting in accordance with FASC 805. Utilities in Ohio continue to face downward pressure on operating margins due to the evolving regulatory environment, which is moving towards a market-based competitive pricing mechanism. At the same time, declining energy prices are also reducing operating margins across the utility industry. These competitive forces could adversely impact the future operating performance of DPL and may result in impairment of its goodwill.
Goodwill is not amortized, but is evaluated for impairment at least annually or more frequently if impairment indicators are present. In evaluating the potential impairment of goodwill, we make estimates and assumptions about revenue, operating cash flows, capital expenditures, growth rates and discount rates based on our budgets and long term forecasts, macroeconomic projections, and current market expectations of returns on similar assets. There are inherent uncertainties related to these factors and management’s judgment in applying these factors. Generally, the fair value of a reporting unit is determined using a discounted cash flow valuation model. We could be required to evaluate the potential impairment of goodwill outside of the required annual assessment process if we experience situations, including but not limited to: deterioration in general economic conditions, operating or regulatory environment; increased competitive environment; increase in fuel costs particularly when we are unable to pass along such costs to customers; negative or declining cash flows; loss of a key contract or customer particularly when we are unable to replace it on equally favorable terms; or adverse actions or assessments by a regulator. These types of events and the resulting analyses could result in goodwill impairment expense, which could substantially affect our results of operations for those periods.
DPL will perform its annual goodwill impairment evaluation in the fourth quarter of 2012.
Predecessor and Successor Financial Presentation
DPL’s financial statements and related financial and operating data include the periods before and after the Merger with AES on November 28, 2011, and are labeled as Predecessor and Successor, respectively. In accordance with GAAP, DPL applied push-down accounting to account for the merger. For accounting purposes only, push-down accounting created a new cost basis assigned to assets, liabilities and equity as of the Merger date. Such adjustments are subject to change as AES finalizes its purchase price allocation during the applicable measurement period.
Regulatory Environment
DPL, DP&L and our subsidiaries’ facilities and operations are subject to a wide range of environmental regulations and laws by federal, state and local authorities. As well as imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. In the normal course of business, we have investigatory and remedial activities underway at these facilities to comply, or to determine compliance, with such regulations. We record liabilities for losses that are probable of occurring and can be reasonably estimated.
Carbon and Other Greenhouse Gas Emissions
There is an ongoing concern nationally and internationally about global climate change and the contribution of emissions of GHGs, including most significantly CO2. This concern has led to regulation and interest in legislation at the federal level, actions at the state level as well as litigation relating to GHG emissions. In 2007, a U.S.
Supreme Court decision upheld that the USEPA has the authority to regulate GHG emissions under the CAA. In April 2009, the USEPA issued a proposed endangerment finding under the CAA. The proposed finding determined that CO2 and other GHGs from motor vehicles threaten the health and welfare of future generations by contributing to climate change. This endangerment finding became effective in January 2010. On June 26, 2012, the U.S. Court of Appeals for the District of Columbia upheld the endangerment finding and other GHG regulations following challenges from industry and state opponents.
As a result of this endangerment finding and other USEPA regulations, emissions of CO2 and other GHGs from certain electric generating units and other stationary sources are subject to regulation. Increased pressure for GHG emissions reduction is also coming from investor organizations and the international community. Environmental advocacy groups are also focusing considerable attention on GHG emissions from power generation facilities and their potential role in climate change. Approximately 98% of the energy we produce is generated by coal. DP&L’s share of GHG emissions at generating stations we own and co-own is approximately 16 million tons annually. If we are required to implement control of CO2 and other GHGs at generation facilities, the cost to DPL and DP&L of such reductions could be material.
Clean Water Act
In April 2012, DP&L received a notice of violation (NOV) related to the construction of the Carter Hollow landfill at the J.M. Stuart station. The NOV indicated that construction activities caused sediment to flow into downstream creeks. DP&L expects to install sedimentation ponds as part of the runoff control measures to address this issue. We expect the impact of this NOV to be immaterial.
SB 221 Requirements
SB 221 and the implementation rules contain targets relating to advanced energy portfolio standards, renewable energy, demand reduction and energy efficiency standards. The standards require that, by the year 2025, 25% of the total number of kWh of electricity sold by the utility to retail electric consumers must come from alternative energy resources, which include “advanced energy resources” such as distributed generation, clean coal, advanced nuclear, energy efficiency and fuel cell technology; and “renewable energy resources” such as solar, hydro, wind, geothermal and biomass. At least half of the 25% must be generated from renewable energy resources, including 0.5% from solar energy. The renewable energy portfolio, energy efficiency and demand reduction standards began in 2009 with increased percentage requirements each year thereafter. The annual targets for energy efficiency and peak demand reductions began in 2009 with annual increases. Energy efficiency programs are expected to save 22.3% by 2025 and peak demand reductions are expected to reach 7.75% by 2018 compared to a baseline energy usage. If any targets are not met, compliance penalties will apply, unless the PUCO makes certain findings that would excuse performance.
SB 221 also contains provisions for determining whether an electric utility has significantly excessive earnings. The PUCO issued general rules for calculating the earnings and comparing them to a comparable group to determine whether there were significantly excessive earnings. Pursuant to the ESP Stipulation, DP&L becomes subject to the SEET in 2013 based on 2012 earnings results and the SEET may have a material effect on our results of operations, financial condition and cash flows.
SB 221 also requires that all Ohio distribution utilities file either an ESP or MRO. Under the MRO, a periodic competitive bid process will set the retail generation price after the utility demonstrates that it can meet certain market criteria and bid requirements. Also, under this option, utilities that still own generation in the state are required to phase-in the MRO over a period of not less than five years. An ESP may allow for adjustments to the SSO for costs associated with environmental compliance; fuel and purchased power; construction of new or investment in specified generating facilities; and the provision of standby and default service, operating, maintenance, or other costs including taxes. As part of its ESP, a utility is permitted to file an infrastructure improvement plan that will specify the initiatives the utility will take to rebuild, upgrade, or replace its electric distribution system, including cost recovery mechanisms. Both MRO and ESP options involve a “significantly excessive earnings test” based on the earnings of comparable companies with similar business and financial risks. On March 30, 2012, DP&L filed with the PUCO for approval of its next SSO to replace the existing ESP that expires on December 31, 2012. The initial filing indicated that the proposed MRO rates, if approved by the PUCO, would reduce DP&L’s revenues by about $30 million in the first year after they are applied, based on the level of SSO sales contained in the filing. The filing requested approval of the five-year and five month MRO, which will be effective January 1, 2013, and would phase in market rates over this period. The PUCO is currently reviewing the filing and no decision has been made. The outcome of the proceeding is uncertain and could have a material impact on our results.
NOx and SO2 Emissions – CSAPR
The Clean Air Interstate Rule (CAIR) final rules were published on May 12, 2005. CAIR created an interstate trading program for annual NOx emission allowances and made modifications to an existing trading program for SO2. Appeals brought by various parties resulted in a decision by the U.S. Court of Appeals for the District of Columbia Circuit on July 11, 2008 to vacate CAIR and its associated Federal Implementation Plan (FIP). On December 23, 2008, the U.S. Court of Appeals issued an order on reconsideration that permits CAIR to remain in effect until the USEPA issues new regulations that would conform to the CAA requirements and the Court’s July 2008 decision.
In an attempt to conform to the Court’s decision, on July 6, 2010, the USEPA proposed the Clean Air Transport Rule (CATR). CATR was finalized as the Cross-State Air Pollution Rule (CSAPR) on July 6, 2011, but subsequent litigation has resulted in CSAPR’s implementation being delayed indefinitely. CSAPR creates four separate trading programs: two SO2 areas (Group 1 and Group 2); and two NOx reduction requirements (annual and ozone season). Group 1 states (16 states including Ohio) will have to meet a 2012 cap and additional reductions in 2014. Group 2 states (7 states) will only have to meet the 2012 cap. We do not believe the rule will have a material effect on our operations in 2012. The Ohio EPA has a State Implementation Plan (SIP) that incorporates the CAIR program requirements, which remain in effect pending judicial review of CSAPR. If CSAPR becomes effective, the USEPA is expected to institute a FIP in lieu of state SIPs and allow for the states to develop SIPs for approval as early as 2013. DP&L is unable to estimate the effect of the new requirements; however, CSAPR could have a material adverse effect on our operations.
Competition and PJM Pricing
RPM Capacity Auction Price
The PJM RPM capacity base residual auction for the 2015/2016 period cleared at a per megawatt price of $136/day for our RTO area. The per megawatt prices for the periods 2014/2015, 2013/2014, 2012/2013, and 2011/2012 were $126/day, $28/day, $16/day, and $110/day, respectively, based on previous auctions. Future RPM auction results will be dependent not only on the overall supply and demand of generation and load, but may also be impacted by congestion as well as PJM’s business rules relating to bidding for demand response and energy efficiency resources in the RPM capacity auctions. The SSO retail costs and revenues are included in the RPM rider. Therefore increases in customer switching causes more of the RPM capacity costs and revenues to be excluded from the RPM rider calculation. We cannot predict the outcome of future auctions or customer switching but based on actual results attained in 2011, we estimate that a hypothetical increase or decrease of $10 in the capacity auction price would result in an annual impact to net income of approximately $5.1 million and $3.8 million for DPL and DP&L, respectively. These estimates do not, however, take into consideration the other factors that may affect the impact of capacity revenues and costs on net income such as the levels of customer switching,
our generation capacity, the levels of wholesale revenues and our retail customer load. These estimates are discussed further within Commodity Pricing Risk under the Market Risk section of this Management Discussion & Analysis.
Ohio Competitive Considerations and Proceedings
Since January 2001, DP&L’s electric customers have been permitted to choose their retail electric generation supplier. DP&L continues to have the exclusive right to provide delivery service in its state certified territory and the obligation to supply retail generation service to customers that do not choose an alternative supplier. The PUCO maintains jurisdiction over DP&L’s delivery of electricity, SSO and other retail electric services.
Lower market prices for power have resulted in increased levels of competition to provide transmission and generation services. This in turn led to approximately 47% and 56% of DP&L’s customers to switch their retail electric services to CRES providers during 2011 and as of June 30, 2012, respectively. DPLER, an affiliated company and one of the registered CRES providers, has been marketing transmission and generation services to DP&L customers.
The following table provides a summary of the number of electric customers and volumes provided by all CRES providers in our service territory during the years ended December 31, 2011, 2010 and 2009:
Year Ended December 31, 2011 | Year Ended December 31, 2010 | Year Ended December 31, 2009 | ||||||||||||||||||||||
Electric Customers | Sales (in Millions of kWh) | Electric Customers | Sales (in Millions of kWh) | Electric Customers | Sales (in Millions of kWh) | |||||||||||||||||||
Supplied by DPLER | ||||||||||||||||||||||||
Residential | 22,314 | 113 | 33 | 1 | – | – | ||||||||||||||||||
Commercial | 10,485 | 1,830 | 6,521 | 1,094 | 221 | 983 | ||||||||||||||||||
Industrial | 623 | 2,933 | 533 | 2,453 | 44 | 68 | ||||||||||||||||||
Other | 3,245 | 855 | 1,272 | 869 | 125 | 413 | ||||||||||||||||||
Supplied by DPLER | 36,667 | 5,731 | 8,359 | 4,417 | 390 | 1,464 | ||||||||||||||||||
Supplied by non-affiliated CRES providers | ||||||||||||||||||||||||
Residential | 21,261 | 97 | 35 | – | – | – | ||||||||||||||||||
Commercial | 5,706 | 492 | 722 | 67 | 11 | 3 | ||||||||||||||||||
Industrial | 321 | 232 | 59 | 73 | 15 | 13 | ||||||||||||||||||
Other | 524 | 41 | 35 | 5 | 18 | – | ||||||||||||||||||
Supplied by non-affiliated CRES providers | 27,812 | 862 | 851 | 145 | 44 | 16 | ||||||||||||||||||
Total supplied in our service territory by DPLER and other CRES providers | ||||||||||||||||||||||||
Residential | 43,575 | 210 | 68 | 1 | – | – | ||||||||||||||||||
Commercial | 16,191 | 2,322 | 7,243 | 1,161 | 232 | 986 | ||||||||||||||||||
Industrial | 944 | 3,165 | 592 | 2,526 | 59 | 81 | ||||||||||||||||||
Other | 3,769 | 896 | 1,307 | 874 | 143 | 413 | ||||||||||||||||||
Total supplied in our service territory by DPLER and other CRES providers | 64,479 | 6,593 | 9,210 | 4,562 | 434 | 1,480 | ||||||||||||||||||
Distribution sales by DP&L in our service territory (1) | ||||||||||||||||||||||||
Residential | 454,697 | 5,354 | 455,572 | 5,522 | 456,144 | 5,120 | ||||||||||||||||||
Commercial | 50,123 | 3,700 | 50,155 | 3,741 | 50,141 | 3,678 | ||||||||||||||||||
Industrial | 1,757 | 3,545 | 1,769 | 3,582 | 1,773 | 3,353 | ||||||||||||||||||
Other | 6,804 | 1,423 | 6,725 | 1,432 | 6,562 | 1,386 | ||||||||||||||||||
Distribution sales by DP&L in our service territory (1) | 513,381 | 14,022 | 514,221 | 14,277 | 514,620 | 13,537 |
(1) | The kWh sales include all distribution sales, including those whose power is supplied by non-affiliated CRES providers. |
The following table provides a summary of the number of electric customers and volumes provided by all CRES providers in our service territory during the three and six months ended June 30, 2012 and 2011:
Three months ended June 30, 2012 | Three months ended June 30, 2011 | |||||||||||||||
Electric Customers | Sales (in Millions of kWh) | Electric Customers | Sales (in Millions of kWh) | |||||||||||||
Supplied by DPLER | 50,157 | 1,540 | 12,033 | 1,419 | ||||||||||||
Supplied by non-affiliated CRES providers | 49,901 | 465 | 4,996 | 164 | ||||||||||||
Total supplied in our service territory by DPLER and other CRES providers | 100,058 | 2,005 | 17,029 | 1,583 | ||||||||||||
Distribution sales by DP&L in our service territory(a) | 512,675 | 3,375 | 513,107 | 3,268 |
(a) | The kWh sales include all distribution sales, including those whose power is supplied by non-affiliated CRES providers. |
Six months ended June 30, 2012 | Six months ended June 30, 2011 | |||||||||||||||
Electric Customers | Sales (in Millions of kWh) | Electric Customers | Sales (in Millions of kWh) | |||||||||||||
Supplied by DPLER | 50,157 | 2,997 | 12,033 | 2,764 | ||||||||||||
Supplied by non-affiliated CRES providers | 49,901 | 866 | 4,996 | 282 | ||||||||||||
Total supplied in our service territory by DPLER and other CRES providers | 100,058 | 3,863 | 17,029 | 3,046 | ||||||||||||
Distribution sales by DP&L in our service territory(a) | 512,675 | 6,899 | 513,107 | 6,898 |
(a) | The kWh sales include all distribution sales, including those whose power is supplied by non-affiliated CRES providers. |
The volumes supplied by DPLER represent approximately 41%, 31% and 11% of DP&L’s total distribution volumes during the years ended December 31, 2011, 2010 and 2009, respectively. The volumes supplied by DPLER represent approximately 46% and 43% of DP&L’s total distribution volumes during the three months ended June 30, 2012 and 2011, respectively, and 43% and 40% during the six months ended June 30, 2012 and 2011, respectively. We currently cannot determine the extent to which customer switching to CRES providers will occur in the future and the effect this will have on our operations, but any additional switching could have a significant adverse effect on our future results of operations, financial condition and cash flows.
As of December 31, 2011, approximately 47% of DP&L’s load has switched to CRES providers with DPLER acquiring 87% of the switched load. For the calendar year 2011, customer switching negatively affected DPL’s gross margin by approximately $58 million compared to the 2010 effect of approximately $17 million. For the calendar year 2011, customer switching negatively affected DP&L’s gross margin by approximately $104 million compared to the 2010 effect of approximately $53 million.
As of June 30, 2012, approximately 56% of DP&L’s load has switched to CRES providers with DPLER acquiring 78% of the switched load. For the six months ended June 30, 2012, customer switching negatively
affected DPL’s gross margin by approximately $59.0 million compared to the 2011 effect of approximately $20.0 million. For the six months ended June 30, 2012, customer switching negatively affected DP&L’s gross margin by approximately $110.0 million compared to the 2011 effect of approximately $36.0 million.
Several communities in DP&L’s service area have passed ordinances allowing the communities to become government aggregators for the purpose of offering alternative electric generation supplies to their citizens. To date, a number of organizations have filed with the PUCO to initiate aggregation programs. If a number of the larger organizations move forward with aggregation, it could have a material effect on our earnings. See “Risk Factors” for more information.
Fuel and Commodity Prices
The coal market is a global market in which domestic prices are affected by international supply disruptions and demand balance. In addition, domestic issues like government-imposed direct costs and permitting issues are affecting mining costs and supply availability. Our approach is to hedge the fuel costs for our anticipated electric sales. For the year ending December 31, 2012, we have hedged substantially all our coal requirements to meet our committed sales. We may not be able to hedge the entire exposure of our operations from commodity price volatility. If our suppliers do not meet their contractual commitments or we are not hedged against price volatility and we are unable to recover costs through the fuel and purchased power recovery rider, our results of operations, financial condition or cash flows could be materially affected.
Effective January 2010, the SSO retail customer portion of fuel price changes, including coal requirements and purchased power costs, was reflected in the implementation of the fuel and purchased power recovery rider, subject to PUCO review. An audit of 2010 fuel costs occurred in 2011 and issues raised were resolved by a Stipulation approved by the PUCO in November 2011. As a result of this approval, DP&L recorded a $25 million pretax ($16 million net of tax) adjustment. The adjustment was due to the reversal of a provision recorded in accordance with the regulatory accounting rules. An audit of 2011 fuel costs is currently ongoing.
Financial Overview
In this Management’s Discussion and Analysis of Results of Operations and Financial Condition, we have included disclosure of the combined Predecessor and Successor results of operations and cash flows. Such combined presentation is considered to be a non-GAAP disclosure. We have included such disclosure because we believe it facilitates the comparison of 2011 operating and financial performance to other periods, and because the core operations of DPL have not changed as a result of the Merger.
Years Ended December 31, 2011, 2010 and 2009
For the year ended December 31, 2011, Net income for DPL was $144.3 million, compared to Net income of $290.3 million for the same period in 2010. The results of operations for both DPL and DP&L are separately discussed in more detail in the following pages.
The following table summarizes the significant components of DPL’s net income for the years ended December 31, 2011 (Combined), 2010 and 2009:
Combined | Successor | Predecessor | ||||||||||||||||||
Year ended December 31, 2011 | November 28, 2011 through December 31, 2011 | January 1, 2011 through November 27, 2011 | Years ended December 31, | |||||||||||||||||
2010 | 2009 | |||||||||||||||||||
($ in millions) | ||||||||||||||||||||
Total operating revenues | $ | 1,827.8 | $ | 156.9 | $ | 1,670.9 | $ | 1,831.4 | $ | 1,539.4 | ||||||||||
Total cost of fuel | 391.6 | 35.8 | 355.8 | 383.9 | 330.4 | |||||||||||||||
Net purchased power | 441.3 | 36.7 | 404.6 | 387.4 | 260.2 | |||||||||||||||
Amortization of intangibles | 11.6 | 11.6 | - | - | - | |||||||||||||||
Total cost of revenues | 844.5 | 84.1 | 760.4 | 771.3 | 590.6 |
Combined | Successor | Predecessor | ||||||||||||||||||
Year ended December 31, 2011 | November 28, 2011 through December 31, 2011 | January 1, 2011 through November 27, 2011 | Years ended December 31, | |||||||||||||||||
2010 | 2009 | |||||||||||||||||||
($ in millions) | ||||||||||||||||||||
�� | ||||||||||||||||||||
Total gross margin (a) | 983.3 | 72.8 | 910.5 | 1,060.1 | 948.8 | |||||||||||||||
Operating expenses | ||||||||||||||||||||
Operation and maintenance | 425.3 | 47.5 | 377.8 | 340.6 | 306.5 | |||||||||||||||
Depreciation and amortization | 141.0 | 11.6 | 129.4 | 139.4 | 145.5 | |||||||||||||||
General taxes | 83.1 | 7.6 | 75.5 | 75.7 | 68.6 | |||||||||||||||
Total operating expense | 649.4 | 66.7 | 582.7 | 555.7 | 520.6 | |||||||||||||||
Operating income | 333.9 | 6.1 | 327.8 | 504.4 | 428.2 | |||||||||||||||
Investment income / (expense) | 0.5 | 0.1 | 0.4 | 1.8 | (0.6 | ) | ||||||||||||||
Interest expense | (85.5 | ) | (11.5 | ) | (74.0 | ) | (70.6 | ) | (83.0 | ) | ||||||||||
Other income / (expense), net | (2.0 | ) | (0.3 | ) | (1.7 | ) | (2.3 | ) | (3.0 | ) | ||||||||||
Income / (loss) before income taxes | 246.9 | (5.6 | ) | 252.5 | 433.3 | 341.6 | ||||||||||||||
Income tax expense | 102.6 | 0.6 | 102.0 | 143.0 | 112.5 | |||||||||||||||
Net income / (loss) | $ | 144.3 | $ | (6.2 | ) | $ | 150.5 | $ | 290.3 | $ | 229.1 |
(a) | For purposes of discussing operating results, we present and discuss gross margins. This format is useful to investors because it allows analysis and comparability of operating trends and includes the same information that is used by management to make decisions regarding our financial performance. |
Results of Operations – DPL Inc.
DPL’s results of operations include the results of its subsidiaries, including the consolidated results of its principal subsidiary DP&L. All material intercompany accounts and transactions have been eliminated in consolidation. A separate specific discussion of the results of operations for DP&L is presented elsewhere in this prospectus.
Income Statement Highlights – DPL
Combined | Successor | Predecessor | ||||||||||||||||||
Year ended December 31, 2011 | November 28, 2011 through December 31, 2011 | January 1, 2011 through November 27, 2011 | Years ended December 31, | |||||||||||||||||
2010 | 2009 | |||||||||||||||||||
($ in millions) | ||||||||||||||||||||
Revenues: | ||||||||||||||||||||
Retail | $ | 1,429.0 | $ | 126.3 | $ | 1,302.7 | $ | 1,404.8 | $ | 1,179.5 | ||||||||||
Wholesale | 129.7 | 8.4 | 121.3 | 142.2 | 122.7 | |||||||||||||||
RTO revenues | 81.7 | 6.6 | 75.1 | 86.6 | 89.4 | |||||||||||||||
RTO capacity revenues | 179.7 | 13.9 | 165.8 | 186.2 | 136.3 | |||||||||||||||
Other revenues | 10.8 | 0.9 | 9.9 | 11.5 | 11.7 | |||||||||||||||
Mark-to-market gains / (losses) | (3.1 | ) | 0.8 | (3.9 | ) | 0.1 | (0.2 | ) | ||||||||||||
Total revenues | 1,827.8 | 156.9 | 1,670.9 | 1,831.4 | 1,539.4 | |||||||||||||||
Cost of revenues: | ||||||||||||||||||||
Fuel costs | 381.2 | 34.8 | 346.4 | 399.5 | 391.7 | |||||||||||||||
Gains from sale of coal | (8.8 | ) | (0.6 | ) | (8.2 | ) | (4.1 | ) | (56.3 | ) | ||||||||||
Gains from sale of emission allowances | - | - | - | (0.8 | ) | (5.0 | ) |
Combined | Successor | Predecessor | ||||||||||||||||||
Year ended December 31, 2011 | November 28, 2011 through December 31, 2011 | January 1, 2011 through November 27, 2011 | Years ended December 31, | |||||||||||||||||
2010 | 2009 | |||||||||||||||||||
($ in millions) | ||||||||||||||||||||
Mark-to-market (gains) / losses | 19.2 | 1.6 | 17.6 | (10.7 | ) | - | ||||||||||||||
Net fuel | 391.6 | 35.8 | 355.8 | 383.9 | 330.4 | |||||||||||||||
Purchased power | 156.2 | 12.9 | 143.3 | 81.5 | 46.9 | |||||||||||||||
RTO charges | 115.1 | 9.2 | 105.9 | 113.4 | 100.9 | |||||||||||||||
RTO capacity charges | 172.9 | 13.1 | 159.8 | 191.9 | 112.4 | |||||||||||||||
Mark-to-market (gains) / losses | (2.9 | ) | 1.5 | (4.4 | ) | 0.6 | - | |||||||||||||
Net purchased power | 441.3 | 36.7 | 404.6 | 387.4 | 260.2 | |||||||||||||||
Amortization of intangibles | 11.6 | 11.6 | - | - | - | |||||||||||||||
Total cost of revenues | 844.5 | 84.1 | 760.4 | 771.3 | 590.6 | |||||||||||||||
Gross margins (a) | $ | 983.3 | $ | 72.8 | $ | 910.5 | $ | 1,060.1 | $ | 948.8 | ||||||||||
Gross margin as a percentage of revenues | 53.8 | % | 46.4 | % | 54.5 | % | 57.9 | % | 61.6 | % | ||||||||||
Operating income | $ | 333.9 | $ | 6.1 | $ | 327.8 | $ | 504.4 | $ | 428.2 |
(a) | For purposes of discussing operating results, we present and discuss gross margins. This format is useful to investors because it allows analysis and comparability of operating trends and includes the same information that is used by management to make decisions regarding our financial performance. |
Revenues
Retail customers, especially residential and commercial customers, consume more electricity on warmer and colder days. Therefore, our retail sales volume is affected by the number of heating and cooling degree days occurring during a year. Cooling degree days typically have a more significant effect than heating degree days since some residential customers do not use electricity to heat their homes.
Years ended December 31, | ||||||||||||
Number of days | 2011 | 2010 | 2009 | |||||||||
Heating degree days (a) | 5,368 | 5,636 | 5,561 | |||||||||
Cooling degree days (a) | 1,160 | 1,245 | 734 |
(a) | Heating and cooling degree days are a measure of the relative heating or cooling required for a home or business. The heating degrees in a day are calculated as the difference of the average actual daily temperature below 65 degrees Fahrenheit. If the average temperature on March 20th was 40 degrees Fahrenheit, the heating degrees for that day would be the 25 degree difference between 65 degrees and 40 degrees. In a similar manner, cooling degrees in a day are the difference of the average actual daily temperature in excess of 65 degrees Fahrenheit. |
Since we plan to utilize our internal generating capacity to supply our retail customers’ needs first, increases in retail demand may decrease the volume of internal generation available to be sold in the wholesale market and vice versa. The wholesale market covers a multi-state area and settles on an hourly basis throughout the year. Factors impacting our wholesale sales volume each hour of the year include: wholesale market prices; our retail demand; retail demand elsewhere throughout the entire wholesale market area; our plants’ and other utility plants’ availability to sell into the wholesale market and weather conditions across the multi-state region. Our plan is to make wholesale sales when market prices allow for the economic operation of our generation facilities not being utilized to meet our retail demand or when margin opportunities exist between the wholesale sales and power purchase prices.
The following table provides a summary of changes in revenues from prior periods:
2011 vs. 2010 | 2010 vs. 2009 | |||||||
($ in millions) | ||||||||
Retail: | ||||||||
Rate | $ | 45.9 | $ | 149.0 | ||||
Volume | (29.1 | ) | 75.2 | |||||
Other | 6.7 | 0.9 | ||||||
Total retail change | 23.5 | 225.1 | ||||||
Wholesale: | ||||||||
Rate | 15.3 | 31.2 | ||||||
Volume | (27.8 | ) | (11.7 | ) | ||||
Total wholesale change | (12.5 | ) | 19.5 | |||||
RTO capacity and other: | ||||||||
RTO capacity and other revenues | (11.4 | ) | 47.1 | |||||
Other: | ||||||||
Unrealized MTM | (3.2 | ) | 0.3 | |||||
Total revenues change | $ | (3.6 | ) | $ | 292.0 |
For the year ended December 31, 2011, Revenues decreased $3.6 million to $1,827.8 million from $1,831.4 million in the same period of the prior year. This decrease was primarily the result of decreased retail and wholesale volumes, decreased RTO capacity and other revenues, offset by increased retail and wholesale rates and increased other miscellaneous retail revenues. The revenue components for the year ended December 31, 2011 are further discussed below:
· | Retail revenues increased $23.5 million resulting primarily from a 3.4% increase in average retail rates due largely to the implementation of the fuel and energy efficiency riders, an increase in the TCRR and RPM riders, combined with the incremental effect of the recovery of costs under the EIR, as well as improved economic conditions. This increase in the average retail rates was partially offset by the effect of lower revenues due to customer switching which has resulted from increased levels of competition to provide transmission and generation services in our service territory. Retail sales volume experienced a 2.1% decrease compared to the prior year period largely due to unfavorable weather. The unfavorable weather conditions resulted in a 6% decrease in the number of cooling degree days to 1,160 days from 1,245 days in 2010. The above resulted in a favorable $45.9 million retail price variance and an unfavorable $29.1 million retail sales volume variance. |
· | Wholesale revenues decreased $12.5 million primarily as a result of a 19.6% decrease in wholesale sales volume which was largely a result of lower generation by our power plants, partially offset by a 13.4% increase in wholesale average prices. This resulted in an unfavorable $27.8 million wholesale sales volume variance partially offset by a favorable wholesale price variance of $15.3 million. |
· | RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, decreased $11.4 million compared to the same period in 2010. This decrease in RTO capacity and other revenues was primarily the result of a $6.5 million decrease in revenues realized from the PJM capacity auction, including a $4.9 million decrease in transmission, congestion and other revenues. |
For the year ended December 31, 2010, Revenues increased $292.0 million, or 19%, to $1,831.4 million from $1,539.4 million in the same period of the prior year. This increase was primarily the result of higher average retail and wholesale rates, higher retail sales volume, and increased RTO capacity and other revenues, partially offset by lower wholesale sales volume. The revenue components for the year ended December 31, 2010 are further discussed below:
· | Retail revenues increased $225.1 million resulting primarily from a 12% increase in average retail rates due largely to the implementation of the fuel and energy efficiency riders, an increase in the TCRR and RPM riders, combined with the incremental effect of the recovery of costs under the EIR. This increase in the average retail rates was partially offset by the effect of lower revenues due to customer switching which has resulted from increased levels of competition to provide transmission and generation services in our service territory. Retail sales volume had a 6% increase compared to those in the prior year period largely due to more favorable weather and improved economic conditions. The favorable weather conditions resulted in a 70% increase in the number of cooling degree days to 1,245 days from 734 days in 2009. The above resulted in a favorable $149.0 million retail price variance and a favorable $75.2 million retail sales volume variance. |
· | Wholesale revenues increased $19.5 million primarily as a result of a 28% increase in wholesale average prices, partially offset by a 10% decrease in wholesale sales volume which was largely a result of lower generation by our power plants and increased retail sales volume. This resulted in a favorable $31.2 million wholesale price variance partially offset by an unfavorable wholesale sales volume variance of $11.7 million. |
· | RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, increased $47.1 million compared to the same period in 2009. This increase in RTO capacity and other revenues was primarily the result of a $49.9 million increase in revenues realized from the PJM capacity auction, partially offset by a $2.8 million decrease in transmission, congestion and other revenues. |
DPL – Cost of Revenues
For the year ended December 31, 2011:
· | Net fuel costs, which include coal, gas, oil and emission allowance costs, increased $7.7 million, or 2%, compared to 2010, primarily due to increased mark-to-market losses on coal contracts partially offset by decreased fuel costs. During the year ended December 31, 2011, DP&L realized $8.8 million in gains from the sale of coal, compared to $4.1 million realized during the same period in 2010. In addition to these gains, there was a 12% decrease in the volume of generation at our plants. Also offsetting the increase in fuel costs was a $15 million decrease due to an adjustment as a result of the approval of the fuel settlement agreement by the PUCO. The adjustment was due to the reversal of a provision recorded in accordance with the regulatory accounting rules. |
· | Net purchased power increased $53.9 million, or 14%, compared to the same period in 2010 due largely to an increase of $74.7 million in purchased power partially offset by a decrease of $17.3 million in RTO capacity and other charges which were incurred as a member of PJM, including costs associated with DP&L’s load obligations for retail customers. This increase included the net impact of the deferral and recovery of DP&L’s transmission, capacity and other PJM-related charges. The increase in purchased power of $74.7 million was comprised of a $100.3 million increase associated with higher purchased power volumes due to lower internal generation partially offset by a $25.6 million decrease related to lower average market prices for purchased power. We purchase power to satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages or when market prices are below the marginal costs associated with our generating facilities. |
For the year ended December 31, 2010:
· | Net fuel costs, which include coal, gas, oil and emission allowance costs, increased $53.5 million, or 16%, compared to 2009, primarily due to the impact of lower gains realized from the sale of DP&L’s coal and excess emission allowances. During the year ended December 31, 2010, DP&L realized $4.1 million and $0.8 million in gains from the sale of coal and excess emission allowances, respectively, compared to $56.3 million and $5.0 million, respectively, realized during the same period in 2009. The effect of these lower gains was partially offset by the impact of a 2% decrease in the volume of generation by our plants. |
· | Net purchased power increased $127.2 million, or 49%, compared to the same period in 2009 due largely to an increase of $92.0 million in RTO capacity and other charges which were incurred as a member of PJM, including costs associated with DP&L’s load obligations for retail customers. This increase included the net impact of the deferral and recovery of DP&L’s transmission, capacity and other PJM-related charges. Also contributing to the increase in net purchased power was a $37.7 million increase related to higher average market prices for purchased power, partially offset by a $2.5 million decrease associated with lower purchased power volumes. We purchase power to satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages or when market prices are below the marginal costs associated with our generating facilities. |
DPL - Operation and Maintenance
2011 vs. 2010 | ||||
($ in millions) | ||||
Merger related costs | $ | 53.6 | ||
Low-income payment program(1) | 14.6 | |||
Generating facilities operating and maintenance expenses | 12.9 | |||
Maintenance of overhead transmission and distribution lines | 9.1 | |||
Competitive retail operations | 7.6 | |||
Insurance settlement, net | 3.4 | |||
Health insurance / long-term disability | (6.2 | ) | ||
Pension expense | (3.3 | ) | ||
Other, net | (7.0 | ) | ||
Total operation and maintenance expense | $ | 84.7 |
(1) | There is a corresponding increase in Revenues associated with this program resulting in no impact to Net income. |
During the year ended December 31, 2011, Operation and maintenance expense increased $84.7 million, or 25%, compared to the same period in 2010. This variance was primarily the result of:
· | increased costs related to the Merger with AES, |
· | increased assistance for low-income retail customers which is funded by the USF revenue rate rider, |
· | increased expenses for generating facilities largely due to the length and timing of planned outages at jointly-owned production units relative to the same period in 2010, |
· | increased expenses related to the maintenance of overhead transmission and distribution lines primarily as a result of storms, including a significant ice storm in February 2011, |
· | increased marketing, customer maintenance and labor costs associated with the competitive retail business as a result of increased sales volume and number of customers, and |
· | a prior year insurance settlement that reimbursed us for legal costs associated with our litigation against certain former executives. |
These increases were partially offset by:
· | lower health insurance and disability costs primarily due to fewer employees going onto long-term disability during the current year as compared to the same period in 2010, and |
· | lower pension expenses primarily related to a $40 million contribution to the pension plan during 2011. |
2010 vs. 2009 | ||||
($ in millions) | ||||
Energy efficiency programs(1) | $ | 11.1 | ||
Health insurance / long-term disability | 8.9 | |||
Low-income payment program(1) | 5.2 | |||
Pension | 4.0 | |||
Generating facilities operating and maintenance expenses | 3.8 | |||
Insurance settlement, net | (3.4 | ) | ||
Other, net | 4.5 | |||
Total operation and maintenance expense | $ | 34.1 |
(1) | There is a corresponding increase in Revenues associated with these programs resulting in no impact to Net income. |
During the year ended December 31, 2010, Operation and maintenance expense increased $34.1 million, or 11%, compared to the same period in 2009. This variance was primarily the result of:
· | higher expenses relating to energy efficiency programs that were put in place for our customers during 2009 and 2010, |
· | increased health insurance and disability costs primarily due to a number of employees going on long-term disability, |
· | increased assistance for low-income retail customers which is funded by the USF revenue rate rider, |
· | increased pension costs due largely to a decline in the values of pension plan assets during 2008 and increased benefit costs, and |
· | increased expenses for generating facilities largely due to unplanned outages at jointly-owned production units. |
These increases were partially offset by:
· | an insurance settlement that reimbursed us for legal costs associated with our litigation against certain former executives. |
DPL – Depreciation and Amortization
During the year ended December 31, 2011, Depreciation and amortization expense increased $1.6 million, or 1%, as compared to 2010. The increase primarily reflects the effect of investments in fixed assets partially offset by the impact of a depreciation study which resulted in lower depreciation rates on generation property which were implemented on July 1, 2010, reducing the expense by approximately $4.8 million during the year ended December 31, 2011 compared to the year ended December 31, 2010. Amortization expense increased $11.6 million in 2011, primarily due to the amortization of intangibles acquired in the Merger.
During the year ended December 31, 2010, Depreciation and amortization expense decreased $6.1 million, or 4%, as compared to 2009. The decrease primarily reflects the impact of a depreciation study which resulted in lower depreciation rates on generation property which were implemented on July 1, 2010, reducing the expense by approximately $4.8 million during the year ended December 31, 2010.
DPL – General Taxes
During the year ended December 31, 2011, General taxes increased $7.4 million, or 10%, as compared to 2010. This increase was primarily the result of higher property tax accruals in 2011 compared to 2010 and an unfavorable determination of $4.5 million from the Ohio gross receipts tax audit. Prior to the Merger date, certain excise and other taxes were recorded gross. Effective on the Merger date, certain excise and other taxes are accounted for on a
net basis and recorded as a reduction in revenues. All prior periods have been reclassified for comparability purposes.
During the year ended December 31, 2010, General taxes increased $7.1 million, or 10%, as compared to 2009. This increase was primarily the result of higher property tax accruals in 2010 compared to 2009 and an adjustment to future credits against state gross receipts taxes. Prior to the Merger date, certain excise and other taxes were recorded gross. Effective on the Merger date, certain excise and other taxes are accounted for on a net basis and recorded as a reduction in revenues.
DPL – Investment Income (Loss)
During the year ended December 31, 2011, Investment income (loss) decreased $1.3 million as compared to 2010 primarily as a result of lower average cash and short-term investment balances in 2011 compared to 2010.
During the year ended December 31, 2010, Investment income (loss) increased $2.4 million as compared to 2009 primarily as a result of $1.4 million of expense incurred in 2009 related to the early redemption of debt. In addition, DPL had higher cash and short-term investment balances in 2010 compared to 2009 which resulted in higher investment income.
DPL – Interest Expense
During the year ended December 31, 2011, Interest expense and charge for early redemption of debt increased $14.9 million, or 21%, as compared to 2010 due primarily to a $15.3 million charge for the early redemption of DPL Capital Trust II securities in February 2011 and higher interest cost subsequent to the Merger as a result of the $1.25 billion of debt that was assumed by DPL in connection with the AES Merger.
During the year ended December 31, 2010, Interest expense decreased $12.4 million, or 15%, as compared to 2009 primarily due to the early redemption in December 2009 of $52.4 million of the $195 million 8.125% Note to DPL Capital Trust II and the redemption of DPL’s $175 million 8.00% Senior Notes in March 2009. A premium of $3.7 million was incurred as an expense in 2009 upon the early debt redemption of $52.4 million referred to above.
DPL – Income Tax Expense
During the year ended December 31, 2011, Income tax expense decreased $40.4 million, or 28%, as compared to 2010 primarily due to decreases in pre-tax income partially offset by non-deductible expenses related to the Merger, non-deductible compensation related to the Merger, a reduction in Internal Revenue Code Section 199 tax benefits and a write-off of a deferred tax asset on the termination of the ESOP.
During the year ended December 31, 2010, Income tax expense increased $30.5 million, or 27%, as compared to 2009 primarily due to increases in pre-tax income.
Results of Operations by Segment – DPL Inc.
DPL’s two segments are the Utility segment, comprised of its DP&L subsidiary, and the Competitive Retail segment, comprised of its competitive retail electric service subsidiaries. These segments are discussed further below:
Utility Segment
The Utility segment is comprised of DP&L’s electric generation, transmission and distribution businesses which generate and sell electricity to residential, commercial, industrial and governmental customers. Electricity for the segment’s 24-county service area is primarily generated at eight coal-fired power plants and is distributed to more than 500,000 retail customers who are located in a 6,000 square mile area of West Central Ohio. DP&L also sells electricity to DPLER and any excess energy and capacity is sold into the wholesale market. DP&L’s transmission and distribution businesses are subject to rate regulation by federal and state regulators while rates for its generation business are deemed competitive under Ohio law.
Competitive Retail Segment
The Competitive Retail segment is comprised of the DPLER and MC Squared competitive retail electric service businesses which sell retail electric energy under contract to residential, commercial, industrial and governmental customers who have selected DPLER or MC Squared as their alternative electric supplier. The Competitive Retail segment sells electricity to approximately 70,000 customers currently located throughout Ohio and Illinois. MC Squared, a Chicago-based retail electricity supplier, serves more than 5,900 customers in Northern Illinois. At the end of the second quarter of 2012, MC Squared added approximately 29,000 new customers in Illinois cities as a result of various governmental aggregation agreements. These new customers have not yet been billed and are not included in the customer counts above. The Competitive Retail segment’s electric energy used to meet its sales obligations was purchased from DP&L and PJM. DP&L sells power to DPLER and MC Squared under wholesale agreements. Under these agreements, intercompany sales from DP&L to DPLER and MC Squared are based on fixed-price contracts for each DPLER or MC Squared customer. The price approximates market prices for wholesale power at the inception of each customer’s contract. The Competitive Retail segment has no transmission or generation assets. The operations of the Competitive Retail segment are not subject to cost-of-service rate regulation by federal or state regulators.
Other
Included within Other are other businesses that do not meet the GAAP requirements for separate disclosure as reportable segments as well as certain corporate costs which include amortization of intangibles recognized in conjunction with the Merger and interest expense on DPL’s debt.
Management evaluates segment performance based on gross margin. In the discussions that follow, we have not provided extensive discussions of the results of operations related to 2009 for the Competitive Retail segment because we believe that financial information is not comparable to the 2010 financial information. We have, however, included brief descriptions of the Competitive Retail segment’s financial results for 2009 for informational purposes as required by GAAP following the Income Statement Highlights table below.
See Note 19 of Notes to DPL’s Consolidated Financial Statements for further discussion of DPL’s reportable segments.
The following table presents DPL’s gross margin by business segment:
Combined | Successor | Predecessor | ||||||||||||||||||
Year ended December 31, 2011 | November 28, 2011 through December 31, 2011 | January 1, 2011 through November 27, 2011 | Years ended December 31, | |||||||||||||||||
2010 | 2010 | |||||||||||||||||||
($ in millions) | ||||||||||||||||||||
Utility | $ | 895.5 | $ | 78.5 | $ | 817.0 | $ | 983.4 | $ | 918.0 | ||||||||||
Competitive Retail | 61.5 | 4.8 | 56.7 | 38.5 | 0.7 | |||||||||||||||
Other | 30.4 | (10.1 | ) | 40.5 | 42.7 | 33.7 | ||||||||||||||
Adjustments and Eliminations | (4.1 | ) | (0.4 | ) | (3.7 | ) | (4.5 | ) | (3.6 | ) | ||||||||||
Total consolidated | $ | 983.3 | $ | 72.8 | $ | 910.5 | $ | 1,060.1 | $ | 948.8 |
The financial condition, results of operations and cash flows of the Utility segment are identical in all material respects and for all periods presented, to those of DP&L. We do not believe that additional discussions of the financial condition and results of operations of the Utility segment would enhance an understanding of this business since these discussions are already included under the DP&L discussions below.
Income Statement Highlights – Competitive Retail Segment
Combined | Successor | Predecessor | ||||||||||||||||||
Year ended December 31, 2011 | November 28, 2011 through December 31, 2011 | January 1, 2011 through November 27, 2011 | Years ended December 31, | |||||||||||||||||
2010 | 2009 | |||||||||||||||||||
($ in millions) | ||||||||||||||||||||
Revenues: | ||||||||||||||||||||
Retail | $ | 426.1 | $ | 37.1 | $ | 389.0 | $ | 275.5 | $ | 64.8 | ||||||||||
RTO and other | (0.7 | ) | 1.1 | (1.8 | ) | 1.5 | 0.7 | |||||||||||||
425.4 | 38.2 | 387.2 | 277.0 | 65.5 | ||||||||||||||||
Cost of revenues: | ||||||||||||||||||||
Purchased power | 363.9 | 33.4 | 330.5 | 238.5 | 64.8 | |||||||||||||||
Gross margins (a) | 61.5 | 4.8 | 56.7 | 38.5 | 0.7 | |||||||||||||||
Operation and maintenance expense | 15.4 | 1.7 | 13.7 | 7.8 | 2.7 | |||||||||||||||
Other expenses (income), net | 2.5 | 0.3 | 2.2 | 1.4 | 1.5 | |||||||||||||||
Total expenses, net | 17.9 | 2.0 | 15.9 | 9.2 | 4.2 | |||||||||||||||
Earnings (loss) from continuing operations before income tax | 43.6 | 2.8 | 40.8 | 29.3 | (3.5 | ) | ||||||||||||||
Income tax expense (benefit) | 17.8 | 1.1 | 16.7 | 10.5 | (0.8 | ) | ||||||||||||||
Net income (loss) | $ | 25.8 | $ | 1.7 | $ | 24.1 | $ | 18.8 | $ | (2.7 | ) | |||||||||
Gross margin as a percentage of revenues | 14.5 | % | 12.6 | % | 14.6 | % | 13.9 | % | 1.1 | % |
(a) | For purposes of discussing operating results, we present and discuss gross margins. This format is useful to investors because it allows analysis and comparability of operating trends and includes the same information that is used by management to make decisions regarding our financial performance. |
Competitive Retail Segment – Revenue
For the year ended December 31, 2011, the segment’s retail revenues increased $150.6 million, or 54.7%, as compared to 2010. The increase was primarily driven by increased levels of competition in the competitive retail electric service business in the state of Ohio which in turn has resulted in a significant number of DP&L’s retail customers switching their retail electric service to DPLER or other CRES providers. Also contributing to the year over year increase is $41.7 million of retail revenue from MC Squared which was purchased on February 28, 2011. Primarily as a result of the customer switching discussed above, the Competitive Retail segment sold approximately 6,677 million kWh of power to 40,171 customers in 2011 compared to 4,546 million kWh of power to 9,002 customers during 2010.
For the year ended December 31, 2010, the segment’s retail revenues increased $210.7 million, or 325%, as compared to 2009. The increase was primarily driven by increased levels of competition in the competitive retail electric service business in the state of Ohio which in turn has resulted in a significant number of DP&L’s retail customers switching their retail electric service to DPLER. Primarily as a result of the customer switching discussed above, the Competitive Retail segment sold approximately 4,546 million kWh of power to 9,002 customers during 2010 compared to 1,464 million kWh to 390 customers during 2009.
Competitive Retail Segment – Purchased Power
During the year ended December 31, 2011, the Competitive Retail segment purchased power increased $125.4 million, or 52.6%, as compared to 2010 primarily due to higher purchased power volumes required to satisfy an increase in customer base resulting from customer switching and also $36.9 million relating to MC Squared customers as MC Squared was acquired on February 28, 2011. The Competitive Retail segment’s electric energy used to meet its sales obligations was purchased from DP&L and PJM. Intercompany sales from DP&L to DPLER are based on fixed-price contracts for each DPLER customers which approximate market prices for wholesale power at the inception of each customer’s contract.
During the year ended December 31, 2010, the Competitive Retail segment purchased power increased $173.7 million, or 268%, as compared to 2009 primarily due to higher purchased power volumes required to satisfy an increase in customer base resulting from customer switching. The Competitive Retail segment’s electric energy used to meet its sales obligations was purchased from DP&L and PJM. During 2010, a new wholesale agreement was implemented between DP&L and DPLER. Under this agreement, intercompany sales from DP&L to DPLER were based on fixed-price contracts which approximated market prices for wholesale power. In periods prior to 2010, DPLER’s purchases from DP&L were transacted at prices that approximated DPLER’s sales prices to its end-use retail customers at the date of the agreement.
Competitive Retail Segment – Operation and Maintenance
DPLER’s operation and maintenance expenses include employee-related expenses, accounting, information technology, payroll, legal and other administration expenses. The higher operation and maintenance expense in 2011 as compared to 2010 and 2009 is reflective of increased marketing and customer maintenance costs associated with the increased sales volume and number of customers and the purchase of MC Squared.
Results of Operations – The Dayton Power and Light Company (DP&L)
Income Statement Highlights – DP&L
Years ended December 31, | ||||||||||||
2011 | 2010 | 2009 | ||||||||||
($ in millions) | ||||||||||||
Revenues: | ||||||||||||
Retail | $ | 1,007.4 | $ | 1,133.7 | $ | 1,117.6 | ||||||
Wholesale | 441.2 | 365.6 | 182.1 | |||||||||
RTO revenues | 76.7 | 81.7 | 86.1 | |||||||||
RTO capacity revenues | 152.4 | 157.6 | 115.2 | |||||||||
Mark-to-market gains / (losses) | - | 0.2 | (0.2 | ) | ||||||||
Total revenues | 1,677.7 | 1,738.8 | 1,500.8 | |||||||||
Cost of revenues: | ||||||||||||
Fuel costs | 370.2 | 387.5 | 384.9 | |||||||||
Gains from sale of coal | (8.8 | ) | (4.1 | ) | (56.3 | ) | ||||||
Gains from sale of emission allowances | - | (0.8 | ) | (5.0 | ) | |||||||
Mark-to-market (gains) / losses | 19.2 | (10.7 | ) | - | ||||||||
Net fuel | 380.6 | 371.9 | 323.6 | |||||||||
Purchased power | 121.5 | 81.3 | 46.9 | |||||||||
RTO charges | 114.9 | 109.7 | 99.9 | |||||||||
RTO capacity charges | 165.4 | 191.9 | 112.4 | |||||||||
Mark-to-market (gains) / losses | (0.2 | ) | 0.6 | - | ||||||||
Net purchased power | 401.6 | 383.5 | 259.2 | |||||||||
Total cost of revenues | 782.2 | 755.4 | 582.8 | |||||||||
Gross margins(a) | $ | 895.5 | $ | 983.4 | $ | 918.0 | ||||||
Gross margin as a percentage of revenues | 53.4 | % | 56.6 | % | 61.2 | % | ||||||
Operating income | 319.9 | 450.2 | 421.9 |
(a) | For purposes of discussing operating results, we present and discuss gross margins. This format is useful to investors because it allows analysis and comparability of operating trends and includes the same information that is used by management to make decisions regarding our financial performance. |
DP&L – Revenues
The following table provides a summary of changes in DP&L’s Revenues from prior periods:
2011 vs. 2010 | 2010 vs. 2009 | |||||||
($ in millions) | ||||||||
Retail | ||||||||
Rate | $ | (45.5 | ) | $ | (46.4 | ) | ||
Volume | (87.9 | ) | 60.7 | |||||
Other | 7.1 | 1.8 | ||||||
Total retail change | (126.3 | ) | 16.1 | |||||
Wholesale | ||||||||
Volume | 48.0 | 109.1 | ||||||
Rate | 27.6 | 74.4 | ||||||
Total wholesale change | 75.6 | 183.5 | ||||||
RTO capacity and other | ||||||||
RTO capacity and other revenues | (10.2 | ) | 38.0 | |||||
Other | ||||||||
Unrealized MTM | (0.2 | ) | 0.4 | |||||
Total revenues change | $ | (61.1 | ) | $ | 238.0 |
For the year ended December 31, 2011, Revenues decreased $61.1 million, or 3.5%, to $1,677.7 million from $1,738.8 million in the prior year. This decrease was primarily the result of lower average retail rates, retail sales volumes and decreased RTO capacity and other revenues, partially offset by higher wholesale sales volumes and higher average wholesale prices. The revenue components for the year ended December 31, 2011 are further discussed below:
· | Retail revenues decreased $126.3 million primarily as a result of an 8% decrease in retail sales volumes compared to those in the prior year largely due to unfavorable weather conditions. The unfavorable weather conditions resulted in a 7% decrease in the number of cooling degree days to 1,160 days from 1,245 days in 2010. Although DP&L had a number of customers that switched their retail electric service from DP&L to DPLER, an affiliated CRES provider, DP&L continued to provide distribution services to those customers within its service territory. The average retail rates decreased 4% overall primarily as a result of customers switching from DP&L to DPLER. The remaining distribution services provided by DP&L were billed at a lower rate resulting in a reduction of total average retail rates. The decrease in average retail rates resulting from customers switching was partially offset by the implementation of the fuel and energy efficiency riders, increased TCRR and RPM riders, and the incremental effect of the recovery of costs under the EIR. The above resulted in an unfavorable $87.9 million retail sales volume variance and an unfavorable $45.5 million retail price variance. |
· | Wholesale revenues increased $75.6 million primarily as a result of a 7% increase in average wholesale prices combined with a 13% increase in wholesale sales volume due in large part to the effect of customer switching discussed in the immediately preceding paragraph. DP&L records wholesale revenues from its sale of transmission and generation services to DPLER associated with these switched customers. This resulted in a favorable $48.0 million wholesale volume variance and a $27.6 million favorable wholesale price variance. |
· | RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, decreased $10.2 million compared to the same period in 2010. This decrease in RTO capacity and other revenues was primarily the result of a $5.2 million decrease in revenues realized from the PJM capacity auction, including a decrease of $5.0 million in transmission and congestion revenues. |
For the year ended December 31, 2010, Revenues increased $238.0 million, or 16%, to $1,738.8 million from $1,500.8 million in the prior year. This increase was primarily the result of higher retail and wholesale sales
volumes, higher average wholesale prices as well as increased RTO capacity and other revenues, partially offset by lower average retail rates. The revenue components for the year ended December 31, 2010 are further discussed below:
· | Retail revenues increased $16.1 million primarily as a result of a 6% increase in retail sales volumes compared to those in the prior year period largely due to more favorable weather and improved economic conditions. The favorable weather conditions resulted in a 70% increase in the number of cooling degree days to 1,245 days from 734 days in 2009. Although DP&L had a number of customers that switched their retail electric service from DP&L to DPLER, an affiliated CRES provider, DP&L continued to provide distribution services to those customers within its service territory. The average retail rates decreased 4% overall primarily as a result of customers switching from DP&L to DPLER. The remaining distribution services provided by DP&L were billed at a lower rate resulting in a reduction of total average retail rates. The decrease in average retail rates resulting from customers switching was partially offset by the implementation of the fuel and energy efficiency riders, increased TCRR and RPM riders, and the incremental effect of the recovery of costs under the EIR. The above resulted in a favorable $60.7 million retail sales volume variance and an unfavorable $46.4 million retail price variance. |
· | Wholesale revenues increased $183.5 million primarily as a result of a 26% increase in average wholesale prices combined with a 60% increase in wholesale sales volume due in large part to the effect of customer switching discussed in the immediately preceding paragraph. DP&L records wholesale revenues from its sale of transmission and generation services to DPLER associated with these switched customers. This resulted in a favorable $109.1 million wholesale sales volume variance and a favorable wholesale price variance of $74.4 million. |
· | RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, increased $38.0 million compared to the same period in 2009. This increase in RTO capacity and other revenues was primarily the result of a $42.4 million increase in revenues realized from the PJM capacity auction partially offset by a decrease of $4.4 million in transmission and congestion revenues. |
DP&L – Cost of Revenues
For the year ended December 31, 2011:
· | Net fuel costs, which include coal, gas, oil, and emission allowance costs, increased $8.7 million, or 2%, compared to 2010, primarily due to the impact of mark-to-market losses on coal contracts in 2011 compared to gains in 2010, partially offset by a reduction in fuel costs and an increase in gains on the sale of coal. Also offsetting the increase in fuel costs was a $15 million adjustment as a result of the approval of the fuel settlement agreement by the PUCO. The adjustment was due to the reversal of a provision recorded in accordance with the regulatory accounting rules. |
· | Net purchased power increased $18.1 million, or 5%, compared to 2010, due largely to an increase of $40.2 million in purchased power costs partially offset by a decrease of $21.3 million in RTO capacity and other charges which were incurred as a member of PJM, including costs associated with DP&L’s load obligations for retail customers. This decrease included the net impact of the deferral and recovery of DP&L’s transmission, capacity and other PJM-related charges. Also contributing to the increase in net purchased power was a $54.6 million increase associated with higher purchased power volumes, partially offset by a $14.4 million decrease related to lower average market prices for purchased power. We purchase power to satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages or when market prices are below the marginal costs associated with our generating facilities. |
For the year ended December 31, 2010:
· | Net fuel costs, which include coal, gas, oil, and emission allowance costs, increased $48.3 million, or 15%, compared to 2009, primarily due to the impact of lower gains realized from the sale of DP&L’s coal and |
excess emission allowances. During the year ended December 31, 2010, DP&L realized $4.1 million and $0.8 million in gains from the sale of coal and excess emission allowances, respectively, compared to $56.3 million and $5.0 million, respectively, during 2009. The effect of these lower gains was partially offset by the impact of a 3% decrease in the volume of generation by our plants.
· | Net purchased power increased $124.3 million, or 48%, compared to 2009, due largely to an increase of $89.3 million in RTO capacity and other charges which were incurred as a member of PJM, including costs associated with DP&L’s load obligations for retail customers. This increase included the net impact of the deferral and recovery of DP&L’s transmission, capacity and other PJM-related charges. Also contributing to the increase in net purchased power was a $37.6 million increase related to higher average market prices for purchased power, partially offset by a $2.5 million decrease associated with lower purchased power volumes. We purchase power to satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages or when market prices are below the marginal costs associated with our generating facilities. |
DP&L – Operation and Maintenance
2011 vs. 2010 | ||||
($ in millions) | ||||
Merger related costs | $ | 19.4 | ||
Low-income payment program(1) | 14.6 | |||
Generating facilities operating and maintenance expenses | 12.8 | |||
Maintenance of overhead transmission and distribution lines | 9.1 | |||
Health insurance / long-term disability | (6.3 | ) | ||
Pension expenses | (3.3 | ) | ||
Other, net | (11.6 | ) | ||
Total operation and maintenance expense | $ | 34.7 |
(1) | There is a corresponding increase in Revenues associated with this program resulting in no impact to Net income. |
During the year ended December 31, 2011, Operation and maintenance expense increased $34.7 million, or 11%, compared to 2010. This variance was primarily the result of:
· | increased costs related to the Merger with AES, |
· | increased assistance for low-income retail customers which is funded by the USF revenue rate rider, |
· | increased expenses for generating facilities largely due to the length and timing of planned outages at jointly-owned production units relative to the same period in 2010, and |
· | increased expenses related to the maintenance of overhead transmission and distribution lines primarily as a result of storms, including a significant ice storm in February 2011. |
These increases were partially offset by:
· | lower health insurance and disability costs primarily due to fewer employees going onto long-term disability during the current year as compared to the same period in 2010, and |
· | lower pension expenses primarily related to a $40 million contribution to the pension plan during 2011. |
2010 vs. 2009 | ||||
($ in millions) | ||||
Energy efficiency programs(1) | $ | 11.1 | ||
Health insurance / long-term disability | 8.9 | |||
Low-income payment program(1) | 5.1 |
2010 vs. 2009 | ||||
($ in millions) | ||||
Pension | 4.0 | |||
Generating facilities operating and maintenance expenses | 3.6 | |||
Other, net | 4.0 | |||
Total operation and maintenance expense | $ | 36.7 |
(1) | There is a corresponding increase in Revenues associated with these programs resulting in no impact to Net income. |
During the year ended December 31, 2010, Operation and maintenance expense increased $36.7 million, or 13%, compared to 2009. This variance was primarily the result of:
· | higher expenses relating to energy efficiency programs that were put in place for our customers during 2009 and 2010, |
· | increased health insurance and disability costs primarily due to a number of employees going on long-term disability, |
· | increased assistance for low-income retail customers which is funded by the USF revenue rate rider, |
· | increased pension costs due largely to a decline in the values of pension plan assets during 2008 and increased benefit costs, and |
· | increased expenses for generating facilities largely due to unplanned outages at jointly-owned production units. |
DP&L – Depreciation and Amortization
During the year ended December 31, 2011, Depreciation and amortization expense increased $4.2 million as compared to 2010. The increase primarily reflected the impact of investments in plant and equipment partially offset by the impact of a depreciation study which resulted in lower depreciation rates on generation property which were implemented on July 1, 2010, reducing the expense by $3.4 million during the year ended December 31, 2011 compared to the year ended December 31, 2010.
During the year ended December 31, 2010, Depreciation and amortization expense decreased $4.8 million as compared to 2009. The decrease primarily reflected the impact of a depreciation study which resulted in lower depreciation rates on generation property which were implemented on July 1, 2010, reducing the expense by $3.4 million during the year ended December 31, 2010.
DP&L – General Taxes
During the year ended December 31, 2011, General taxes increased $3.5 million to $75.9 million compared to 2010. This increase was primarily the result of higher property tax accruals in 2011 compared to 2010. Prior to the Merger date, certain excise and other taxes were recorded gross. Effective on the Merger date, certain excise and other taxes are accounted for on a net basis and recorded as a reduction in revenues. All prior periods have been reclassified for comparability purposes.
During the year ended December 31, 2010, General taxes increased $5.2 million to $72.4 million compared to 2009. This increase was primarily the result of higher property tax accruals in 2010 compared to 2009. Prior to the Merger date, certain excise and other taxes were recorded gross. Effective on the Merger date, certain excise and other taxes are accounted for on a net basis and recorded as a reduction in revenues.
DP&L – Investment Income
Investment income realized during 2011 increased $15.6 million over 2010 primarily as a result of the sale of the DPL Inc. stock held by the Master Trust.
Investment income realized during 2010 did not fluctuate significantly from that realized during 2009.
DP&L – Interest Expense
Interest expense recorded during 2011 did not fluctuate significantly from that recorded in 2010.
Interest expense recorded during 2010 did not fluctuate significantly from that recorded in 2009.
DP&L – Income Tax Expense
During the year ended December 31, 2011, Income tax expense decreased $31.0 million compared to 2010 primarily due to decreases in pre-tax income offset by non-deductible compensation expenses related to the Merger, a reduction in Internal Revenue Code Section 199 tax benefits and a write-off of a deferred tax asset on the termination of the ESOP.
During the year ended December 31, 2010, Income tax expense increased $10.7 million compared to 2009 primarily due to increases in pre-tax income.
Three Months Ended June 30, 2012 and 2011
Results of Operations - DPL
Income Statement Highlights – DPL
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
Successor | Predecessor | Successor | Predecessor | |||||||||||||
($ in millions) | ||||||||||||||||
Revenues: | ||||||||||||||||
Retail | $ | 324.2 | $ | 336.5 | $ | 673.5 | $ | 705.9 | ||||||||
Wholesale | 12.3 | 28.7 | 34.7 | 61.1 | ||||||||||||
RTO revenues | 19.7 | 19.5 | 37.9 | 40.9 | ||||||||||||
RTO capacity revenues | 26.6 | 49.7 | 63.5 | 105.0 | ||||||||||||
Other revenues | 2.5 | 2.9 | 5.7 | 5.7 | ||||||||||||
Mark-to-market (losses) / gains | (3.3 | ) | (4.0 | ) | 0.7 | (4.7 | ) | |||||||||
Total revenues | $ | 382.0 | $ | 433.3 | $ | 816.0 | $ | 913.9 | ||||||||
Cost of revenues: | ||||||||||||||||
Fuel costs | $ | 69.0 | $ | 90.0 | $ | 159.6 | $ | 190.9 | ||||||||
Losses / (gains) from sale of coal | 1.9 | (1.2 | ) | 5.3 | (2.9 | ) | ||||||||||
Mark-to-market (gains) / losses | (2.0 | ) | 3.3 | 1.4 | 3.9 | |||||||||||
Net fuel | 68.9 | 92.1 | 166.3 | 191.9 | ||||||||||||
Purchased power | 39.3 | 43.3 | 73.9 | 80.6 | ||||||||||||
RTO charges | 21.6 | 27.1 | 46.1 | 56.4 | ||||||||||||
RTO capacity charges | 22.7 | 47.0 | 56.4 | 102.5 | ||||||||||||
Mark-to-market (gains) / losses | (3.3 | ) | (3.8 | ) | (1.3 | ) | (5.1 | ) | ||||||||
Net purchased power | 80.3 | 113.6 | 175.1 | 234.4 | ||||||||||||
Amortization of intangibles | 19.2 | — | 47.0 | — | ||||||||||||
Total cost of revenues | $ | 168.4 | $ | 205.7 | $ | 388.4 | $ | 426.3 | ||||||||
Gross margins(a) | $ | 213.6 | $ | 227.6 | $ | 427.6 | $ | 487.6 | ||||||||
Gross margin as a percentage of revenues | 56 | % | 53 | % | 52 | % | 53 | % | ||||||||
Operating income | $ | 57.4 | $ | 65.8 | $ | 116.6 | $ | 166.6 |
(a) | For purposes of discussing operating results, we present and discuss gross margins. This format is useful to investors because it allows analysis and comparability of operating trends and includes the same information that is used by management to make decisions regarding our financial performance. |
DPL – Revenues
Retail customers, especially residential and commercial customers, consume more electricity on warmer and colder days. Therefore, our retail sales volume is impacted by the number of heating and cooling degree days occurring during a year. Cooling degree days typically have a more significant impact than heating degree days since some residential customers do not use electricity to heat their homes.
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
Number of days | 2012 Successor | 2011 Predecessor | 2012 Successor | 2011 Predecessor | ||||||||||||
Heating degree days(a) | 455 | 513 | 2,718 | 3,480 | ||||||||||||
Cooling degree days(a) | 400 | 319 | 430 | 319 |
(a) | Heating and cooling degree days are a measure of the relative heating or cooling required for a home or business. The heating degrees in a day are calculated as the difference of the average actual daily temperature below 65 degrees Fahrenheit. If the average temperature on March 20th was 40 degrees Fahrenheit, the heating degrees for that day would be the 25 degree difference between 65 degrees and 40 degrees. In a similar manner, cooling degrees in a day are the difference of the average actual daily temperature in excess of 65 degrees Fahrenheit. |
The following table provides a summary of changes in revenues from the prior period:
Three Months Ended June 30, 2012 vs. 2011 | Six Months Ended June 30, 2012 vs. 2011 | |||||||
($ in millions) | ||||||||
Retail | ||||||||
Rate | $ | (1.5 | ) | $ | 1.5 | |||
Volume | (10.4 | ) | (33.8 | ) | ||||
Other retail | (0.4 | ) | (0.1 | ) | ||||
Total retail change | $ | (12.3 | ) | $ | (32.4 | ) | ||
Wholesale | ||||||||
Rate | $ | (1.7 | ) | $ | 2.2 | |||
Volume | (14.7 | ) | (28.6 | ) | ||||
Total wholesale change | $ | (16.4 | ) | $ | (26.4 | ) | ||
RTO capacity & other | ||||||||
RTO capacity and other RTO revenues | $ | (22.9 | ) | $ | (44.5 | ) | ||
Other | ||||||||
Unrealized MTM | $ | 0.7 | $ | 5.4 | ||||
Miscellaneous | (0.4 | ) | — | |||||
Total other revenue | 0.3 | 5.4 | ||||||
Total revenues change | $ | (51.3 | ) | $ | (97.9 | ) |
For the three months ended June 30, 2012, Revenues decreased $51.3 million to $382.0 million from $433.3 million in the same period of the prior year. This decrease was primarily the result of lower retail and wholesale sales volume, a decrease in retail and wholesale average rates and a decrease in RTO capacity and other RTO revenues.
· | Retail revenues decreased $12.3 million resulting primarily from a 3% decrease in retail sales volume compared to the prior year period largely as a result of customer switching due to increased levels of competition to provide transmission and generation services in our service territory. This decrease in sales volume was partially offset by improved economic conditions as well as a slight increase in average rates. Weather during the three months was slightly favorable with a 25% increase in the number of cooling degree days to 400 days from 319 days in 2011 slightly offset by an 11% decrease in the number of heating |
degree days to 455 days from 513 days in 2011. The above resulted in an unfavorable $10.4 million retail sales volume variance and an unfavorable $1.5 million retail price variance.
· | Wholesale revenues decreased $16.4 million primarily as a result of a 51% decrease in wholesale sales volume which was largely a result of lower generation by our power plants, as well as a 12% decrease in wholesale average prices. This resulted in an unfavorable $14.7 million wholesale sales volume variance and an unfavorable wholesale price variance of $1.7 million. |
· | RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, decreased $22.9 million compared to the same period in 2011. This decrease in RTO capacity and other revenues was the result of a $23.1 million decrease in revenues realized from the PJM capacity auction offset by a slight increase in transmission and congestion revenues. |
For the six months ended June 30, 2012, Revenues decreased $97.9 million to $816.0 million from $913.9 million in the same period of the prior year. This decrease was primarily the result of lower retail and wholesale sales volume and a decrease in RTO capacity and other RTO revenues, partially offset by an increase in retail and wholesale average rates.
· | Retail revenues decreased $32.4 million resulting primarily from a 5% decrease in retail sales volume compared to the prior year period largely due to unfavorable weather. The unfavorable weather conditions resulted in a 22% decrease in the number of heating degree days to 2,718 days from 3,480 days in 2011 offset slightly by a 35% increase in the number of cooling degree days to 430 days from 319 days in 2011. The decrease in sales volume is also due to the effect of lower revenues due to customer switching which has resulted from increased levels of competition to provide transmission and generation services in our service territory. This decrease in sales volume was partially offset by improved economic conditions as well as a slight increase in average rates. The above resulted in an unfavorable $33.8 million retail sales volume variance and a favorable $1.5 million retail price variance. |
· | Wholesale revenues decreased $26.4 million primarily as a result of a 47% decrease in wholesale sales volume which was largely a result of lower generation by our power plants, partially offset by a 7% increase in wholesale average prices. This resulted in an unfavorable $28.6 million wholesale sales volume variance and a favorable wholesale price variance of $2.2 million. |
· | RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, decreased $44.5 million compared to the same period in 2011. This decrease in RTO capacity and other revenues was primarily the result of a $41.5 million decrease in revenues realized from the PJM capacity auction. |
DPL – Cost of Revenues
For the three months ended June 30, 2012:
· | Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $23.2 million, or 25%, during the quarter ended June 30, 2012 compared to the same period in 2011. This decrease was largely due to a $21.0 million decrease in fuel costs driven by a 21% decrease in the volume of generation at our plants. Also contributing to this decrease were unrealized MTM gains of $2.0 million for the three months ended June 30, 2012 versus $3.3 million MTM losses during the same period in 2011. Partially offsetting the decreases were $1.9 million in realized losses from DP&L’s sale of coal, compared to $1.2 million of realized gains during the same period in 2011. |
· | Net purchased power decreased $33.3 million, or 29%, compared to the same period in 2011 due largely to a $29.8 million decrease in RTO capacity and other charges which were incurred as a member of PJM, including costs associated with DP&L’s load obligations for retail customers. This decrease included the net impact of the deferral and recovery of DP&L’s transmission, capacity and other PJM-related charges. |
Purchased power volumes increased 41% while purchased power prices decreased approximately 36% resulting in a decrease of $4.0 million compared to the same period in 2011. We purchase power to satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages or when market prices are below the marginal costs associated with our generating facilities.
· | Amortization of intangibles increased $19.2 million, or 100%, compared to the same period in 2011 due to the application of purchase accounting at the Merger date. |
For the six months ended June 30, 2012:
· | Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $25.6 million, or 13%, during the six months ended June 30, 2012 compared to the same period in 2011. This decrease was largely due to a $31.3 million decrease in fuel costs driven by a 17% decrease in the volume of generation at our plants. Also contributing to this decrease were unrealized MTM losses of only $1.4 million for the six months ended June 30, 2012 versus $3.9 million MTM losses during the same period in 2011. Partially offsetting the decreases were $5.3 million in realized losses from DP&L’s sale of coal, compared to $2.9 million of realized gains during the same period in 2011. |
· | Net purchased power decreased $59.3 million, or 25%, compared to the same period in 2011 due largely to a $56.4 million decrease in RTO capacity and other charges which were incurred as a member of PJM, including costs associated with DP&L’s load obligations for retail customers. This decrease included the net impact of the deferral and recovery of DP&L’s transmission, capacity and other PJM-related charges. Purchased power volumes increased 21% while purchased power prices decreased approximately 24% resulting in a decrease of $6.7 million compared to the same period in 2011. We purchase power to satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages or when market prices are below the marginal costs associated with our generating facilities. |
· | Amortization of intangibles increased $47.0 million, or 100%, compared to the same period in 2011 due to the application of purchase accounting at the Merger date. |
DPL – Operation and Maintenance
Three Months Ended June 30, 2012 vs. 2011 | Six Months Ended June 30, 2012 vs. 2011 | |||||||
($ in millions) | ||||||||
Low-income payment program(1) | $ | 5.2 | $ | 10.4 | ||||
Competitive retail operations | 2.6 | 4.8 | ||||||
Generating facilities operating and maintenance expenses | (0.1 | ) | 1.3 | |||||
Maintenance of overhead transmission and distribution lines | (0.6 | ) | (6.3 | ) | ||||
Merger related costs | (5.4 | ) | (6.0 | ) | ||||
Deferred compensation | (1.8 | ) | (2.0 | ) | ||||
Pension related expense | (0.7 | ) | (1.4 | ) | ||||
Other, net | (2.2 | ) | (1.5 | ) | ||||
Total operation and maintenance expense | $ | (3.0 | ) | $ | (0.7 | ) |
(1) | There is a corresponding increase in Revenues associated with this program resulting in no impact to Net income. |
During the three months ended June 30, 2012, Operation and maintenance expense decreased $3.0 million, or 3%, compared to the same period in 2011. This variance was primarily the result of:
· | a slight decrease in expenses related to the maintenance of overhead transmission and distribution lines, |
· | higher costs in the prior year related to the Merger, |
· | decreased expenses related to deferred compensation arrangements primarily related to fewer equity awards in the current period, and |
· | lower pension expenses primarily related to the elimination of certain unrecognized actuarial losses and prior service costs as a result of purchase accounting due to the Merger. These amounts were previously recorded in Accumulated Other Comprehensive Income and recognized in pension expense over the remaining service life of plan participants. These decreases were partially offset by: |
· | increased assistance for low-income retail customers which is funded by the USF revenue rate rider, and |
· | increased marketing, customer maintenance and labor costs associated with the competitive retail business as a result of increased sales volume and number of customers. |
During the six months ended June 30, 2012, Operation and maintenance expense decreased $0.7 million, compared to the same period in 2011. This variance was primarily the result of:
· | decreased expenses related to the maintenance of overhead transmission and distribution lines primarily as a result of storms, including a significant ice storm in February 2011, |
· | higher costs in the prior year related to the Merger, |
· | decreased expenses related to deferred compensation arrangements primarily related to fewer equity awards in the current periods, and |
· | lower pension expenses primarily related to the elimination of certain unrecognized actuarial losses and prior service costs as a result of purchase accounting due to the Merger. These amounts were previously recorded in Accumulated Other Comprehensive Income and recognized in pension expense over the remaining service life of plan participants. |
These decreases were partially offset by:
· | increased assistance for low-income retail customers which is funded by the USF revenue rate rider, |
· | increased marketing, customer maintenance and labor costs associated with the competitive retail business as a result of increased sales volume and number of customers, and |
· | increased expenses for generating facilities largely due to the length and timing of planned outages at jointly owned production units relative to the same period in 2011. |
DPL – Depreciation and Amortization
For the three and six months ended June 30, 2012, Depreciation and amortization expense decreased $4.0 million, or 11%, and $7.7 million, or 11%, respectively, as compared to 2011. The decreases primarily reflect the effect of the purchase accounting which resulted in estimated fair values of our plants below the carrying values at the Merger date. This was partially offset by increased amortization expense primarily due to amortization resulting from the increase in the estimated value of certain intangibles acquired in the Merger.
DPL – General Taxes
For the three and six months ended June 30, 2012, General taxes increased $1.4 million, or 7%, and decreased $1.6 million, or 4%, respectively, as compared to 2011. The increase was primarily the result of higher property tax accruals in 2012. This decrease was primarily the result of an unfavorable 2011 determination from the Ohio gross receipts tax audit partially offset by higher property tax accruals in 2012 compared to 2011. Prior to the Merger date, certain excise and other taxes were recorded gross. Effective on the Merger date, these taxes are accounted for on a net basis and are recorded as a reduction in revenues for presentation in accordance with AES policy. The 2011 amount was reclassified to conform to this presentation.
DPL – Interest Expense
For the three months ended June 30, 2012, Interest expense increased $14.8 million, or 84%, as compared to 2011 due primarily to higher interest cost subsequent to the Merger as a result of the $1,250.0 million of debt that was assumed by DPL in connection with the AES Merger.
For the six months ended June 30, 2012, Interest expense increased $27.5 million, or 80%, as compared to 2011 due primarily to higher interest cost subsequent to the Merger as a result of the $1,250.0 million of debt that was assumed by DPL in connection with the AES Merger.
DPL – Charge for Early Redemption of Debt
The Charge for early redemption of debt reflects the purchase, in February 2011, of $122.0 million principal of the DPL Capital Trust II 8.125% capital securities in a privately negotiated transaction. As part of this transaction, DPL paid a $12.2 million, or 10% premium, and wrote-off $3.1 million of unamortized discount and issuance costs.
DPL – Income Tax Expense
For the three and six months ended June 30, 2012, Income tax expense decreased $3.9 million, or 24%, and $21.0 million, or 51%, respectively, as compared to 2011 primarily due to decreased pre-tax income, partially offset by increased state income taxes.
Results of Operations by Segment – DPL Inc.
The following table presents DPL’s gross margin by business segment:
Three months ended June 30, | Increase (Decrease) 2012 vs. 2011 | ||||||||||||
2012 | 2011 | ||||||||||||
Successor | Predecessor | ||||||||||||
($ in millions) | |||||||||||||
Utility | $ | 208.7 | $ | 203.4 | $ | 5.3 | |||||||
Competitive Retail | 14.4 | 12.5 | 1.9 | ||||||||||
Other | (8.7 | ) | 12.7 | (21.4 | ) | ||||||||
Adjustments and Eliminations | (0.8 | ) | (1.0 | ) | 0.2 | ||||||||
Total consolidated | $ | 213.6 | $ | 227.6 | $ | (14.0 | ) |
Six months ended June 30, | Increase (Decrease) 2012 vs. 2011 | ||||||||||||
2012 | 2011 | ||||||||||||
Successor | Predecessor | ||||||||||||
($ in millions) | |||||||||||||
Utility | $ | 427.8 | $ | 436.8 | $ | (9.0 | ) | ||||||
Competitive Retail | 29.8 | 28.8 | 1.0 | ||||||||||
Other | (28.3 | ) | 24.0 | (52.3 | ) | ||||||||
Adjustments and Eliminations | (1.7 | ) | (2.0 | ) | 0.3 | ||||||||
Total consolidated | $ | 427.6 | $ | 487.6 | $ | (60.0 | ) |
The financial condition, results of operations and cash flows of the Utility segment are identical in all material respects and for both periods presented, to those of DP&L which are included in this Prospectus. We do not believe that additional discussions of the financial condition and results of operations of the Utility segment would enhance an understanding of this business since these discussions are already included under the DP&L discussions below.
Income Statement Highlights – Competitive Retail Segment
Three months ended June 30, | Increase (Decrease) 2012 vs. 2011 | ||||||||||||
2012 | 2011 | ||||||||||||
Successor | Predecessor | ||||||||||||
($ in millions) | |||||||||||||
Revenues: | |||||||||||||
Retail | $ | 112.6 | $ | 105.3 | $ | 7.3 | |||||||
RTO and other | (2.7 | ) | (3.3 | ) | 0.6 | ||||||||
109.9 | 102.0 | 7.9 | |||||||||||
Cost of revenues: | |||||||||||||
Purchased power | 95.5 | 89.5 | 6.0 | ||||||||||
Gross margins(a) | 14.4 | 12.5 | 1.9 | ||||||||||
Operation and maintenance expense | 5.8 | 3.1 | 2.7 | ||||||||||
Other expenses (income), net | 0.6 | 0.4 | 0.2 | ||||||||||
Total expenses, net | 6.4 | 3.5 | 2.9 | ||||||||||
Earnings (Loss) from continuing operations before income tax | 8.0 | 9.0 | (1.0 | ) | |||||||||
Income tax expense (benefit) | 6.5 | 3.3 | 3.2 | ||||||||||
Net income (Loss) | $ | 1.5 | $ | 5.7 | $ | (4.2 | ) | ||||||
Gross margin as a percentage of revenues | 13 | % | 12 | % |
(a) | For purposes of discussing operating results, we present and discuss gross margins. This format is useful to investors because it allows analysis and comparability of operating trends and includes the same information that is used by management to make decisions regarding our financial performance. |
Six months ended June 30, | Increase (Decrease) 2012 vs. 2011 | ||||||||||||
2012 | 2011 | ||||||||||||
Successor | Predecessor | ||||||||||||
($ in millions) | |||||||||||||
Revenues: | |||||||||||||
Retail | $ | 220.2 | $ | 199.6 | $ | 20.6 | |||||||
RTO and other | 1.8 | (3.6 | ) | 5.4 | |||||||||
222.0 | 196.0 | 26.0 | |||||||||||
Cost of revenues: | |||||||||||||
Purchased power | 192.2 | 167.2 | 25.0 | ||||||||||
Gross margins(a) | 29.8 | 28.8 | 1.0 | ||||||||||
Operation and maintenance expense | 11.0 | 6.1 | 4.9 | ||||||||||
Other expenses (income), net | 1.4 | 1.0 | 0.4 | ||||||||||
Total expenses, net | 12.4 | 7.1 | 5.3 | ||||||||||
Earnings (Loss) from continuing operations before income tax | 17.4 | 21.7 | (4.3 | ) | |||||||||
Income tax expense (benefit) | 9.9 | 9.9 | — | ||||||||||
Net income (Loss) | $ | 7.5 | $ | 11.8 | $ | (4.3 | ) | ||||||
Gross margin as a percentage of revenues | 13 | % | 15 | % |
(a) | For purposes of discussing operating results, we present and discuss gross margins. This format is useful to investors because it allows analysis and comparability of operating trends and includes the same information that is used by management to make decisions regarding our financial performance. |
Competitive Retail Segment – Revenue
For the three months ended June 30, 2012, the segment’s retail revenues increased $7.3 million, or 7%, as compared to 2011. The increase was primarily due to increased retail sales volume from DP&L’s retail customers switching their electric service to DPLER. Increased competition in the competitive retail electric service business
in the state of Ohio has resulted in many of DP&L’s retail customers switching their retail electric service to DPLER or other CRES suppliers. The increased sales volume from switching was partially offset by unfavorable weather conditions resulting in a 12% decrease in the number of heating degree days during the period in 2012 compared to 2011. Primarily as a result of the customer switching discussed above, the Competitive Retail segment sold approximately 1,900 million kWh of power to approximately 70,000 customers for the three months ending June 30, 2012 compared to approximately 1,700 million kWh of power to more than 15,000 customers during the same period of 2011.
For the six months ended June 30, 2012, the segment’s retail revenues increased $20.6 million, or 10%, as compared to 2011. The increase was primarily due to an $8.3 million increase in retail revenue from MC Squared which was purchased on February 28, 2011 combined with increased retail sales volume from DP&L’s retail customers switching their electric service to DPLER. Increased competition in the competitive retail electric service business in the state of Ohio has resulted in many of DP&L’s retail customers switching their retail electric service to DPLER or other CRES suppliers. The increased sales volume from switching and from MC Squared was partially offset by unfavorable weather conditions resulting in a 22% decrease in the number of heating degree days during the period in 2012 compared to 2011. Primarily as a result of the customer switching discussed above, the Competitive Retail segment sold approximately 3,600 million kWh of power to approximately 70,000 customers for the six months ending June 30, 2012 compared to approximately 3,100 million kWh of power to more than 15,000 customers during the same period of 2011.
Competitive Retail Segment – Purchased Power
For the three months ended June 30, 2012, the Competitive Retail segment purchased power increased $6.0 million, or 7%, as compared to 2011 due to higher purchased power volumes required to satisfy an increase in customer base resulting from customer switching. The Competitive Retail segment’s electric energy used to meet its sales obligations was purchased from DP&L and PJM. Intercompany sales from DP&L to DPLER are based on fixed-price contracts for each DPLER customer; the price approximates market prices for wholesale power at the inception of each customer’s contract.
For the six months ended June 30, 2012, the Competitive Retail segment purchased power increased $25.0 million, or 15%, as compared to 2011 due to higher purchased power volumes required to satisfy an increase in customer base resulting from customer switching and power purchased for MC Squared customers for all six months in 2012 versus four months in 2011. The Competitive Retail segment’s electric energy used to meet its sales obligations was purchased from DP&L and PJM. Intercompany sales from DP&L to DPLER are based on fixed-price contracts for each DPLER customer; the price approximates market prices for wholesale power at the inception of each customer’s contract.
Competitive Retail Segment – Operation and Maintenance
For the three months ended June 30, 2012, DPLER’s operation and maintenance expenses include employee-related expenses, accounting, information technology, payroll, legal and other administration expenses. The higher operation and maintenance expense in 2012 as compared to 2011 is reflective of increased marketing and customer maintenance costs associated with the increased sales volume and number of customers.
For the six months ended June 30, 2012, DPLER’s operation and maintenance expenses include employee-related expenses, accounting, information technology, payroll, legal and other administration expenses. The higher operation and maintenance expense in 2012 as compared to 2011 is reflective of increased marketing and customer maintenance costs associated with the increased sales volume and number of customers and the purchase of MC Squared.
Competitive Retail Segment – Income Tax Expense
For the three months ended June 30, 2012, the segment’s income tax expense increased $3.2 million compared to the same period in 2011 due to increased state income tax expenses.
For the six months ended June 30, 2012, the segment’s income tax expense did not change compared to the same period in 2011 as a result of the increased state income taxes noted above offset by pre-tax income.
Results of Operations – DP&L
Income Statement Highlights – DP&L
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
Revenues: | ($ in millions) | |||||||||||||||
Retail | $ | 212.7 | $ | 232.1 | $ | 455.4 | $ | 508.4 | ||||||||
Wholesale | 95.8 | 104.7 | 200.3 | 210.9 | ||||||||||||
RTO revenues | 18.4 | 18.1 | 35.7 | 38.5 | ||||||||||||
RTO capacity revenues | 22.6 | 42.1 | 54.0 | 88.9 | ||||||||||||
Mark-to-market (losses)/gains | (2.9 | ) | (0.1 | ) | 0.8 | — | ||||||||||
Total revenues | $ | 346.6 | $ | 396.9 | $ | 746.2 | $ | 846.7 | ||||||||
Cost of revenues: | ||||||||||||||||
Fuel costs | $ | 68.6 | $ | 86.9 | $ | 157.4 | $ | 186.7 | ||||||||
Losses/(gains) from sale of coal | 1.9 | (1.1 | ) | 5.3 | (2.9 | ) | ||||||||||
Mark-to-market (gains)/losses | (1.9 | ) | 3.3 | 1.5 | 3.9 | |||||||||||
Net fuel | 68.6 | 89.1 | 164.2 | 187.7 | ||||||||||||
Purchased power | 31.1 | 32.8 | 56.6 | 66.7 | ||||||||||||
RTO charges | 20.7 | 27.6 | 44.8 | 56.7 | ||||||||||||
RTO capacity charges | 21.1 | 44.4 | 52.6 | 98.9 | ||||||||||||
Mark-to-market (gains) / losses | (3.6 | ) | (0.4 | ) | 0.2 | (0.1 | ) | |||||||||
Total purchased power | 69.3 | 104.4 | 154.2 | 222.2 | ||||||||||||
Total cost of revenues | $ | 137.9 | $ | 193.5 | $ | 318.4 | $ | 409.9 | ||||||||
Gross margins(a) | $ | 208.7 | $ | 203.4 | $ | 427.8 | $ | 436.8 | ||||||||
Gross margin as a percentage of revenues | 60 | % | 51 | % | 57 | % | 52 | % | ||||||||
Operating Income | $ | 57.0 | $ | 55.8 | $ | 122.0 | $ | 145.1 |
(a) | For purposes of discussing operating results, we present and discuss gross margins. This format is useful to investors because it allows analysis and comparability of operating trends and includes the same information that is used by management to make decisions regarding our financial performance. |
DP&L – Revenues
The following table provides a summary of changes in revenues from the prior period:
Three Months Ended June 30, 2012 vs. 2011 | Six Months Ended June 30, 2012 vs. 2011 | |||||||
($ in millions) | ||||||||
Retail | ||||||||
Rate | $ | (5.4 | ) | $ | (8.8 | ) | ||
Volume | (13.7 | ) | (44.1 | ) | ||||
Other miscellaneous | (0.3 | ) | (0.1 | ) | ||||
Total retail change | (19.4 | ) | (53.0 | ) | ||||
Wholesale | ||||||||
Rate | (2.0 | ) | 3.8 | |||||
Volume | (6.9 | ) | (14.4 | ) | ||||
Total wholesale change | (8.9 | ) | (10.6 | ) | ||||
RTO capacity and other | ||||||||
RTO capacity and other RTO revenues | (19.2 | ) | (37.7 | ) | ||||
Other | ||||||||
Unrealized MTM | $ | (2.8 | ) | $ | 0.8 | |||
Total revenues change | $ | (50.3 | ) | $ | (100.5 | ) |
For the three months ended June 30, 2012, Revenues decreased $50.3 million, or 13%, to $346.6 million from $396.9 million in the prior year. This decrease was primarily the result of lower average retail and wholesale rates, lower retail and wholesale sales volumes and decreased RTO capacity and other revenues. The revenue components for the three months ended June 30, 2012 are further discussed below:
· | Retail revenues decreased $19.4 million primarily due to a 6% decrease in retail sales volumes compared to the prior year largely as a result of customer switching due to increased levels of competition to provide transmission and generation services in our service territory. This decrease in sales volume was partially offset by improved economic conditions. Weather during the three months was slightly favorable with a 25% increase in the number of cooling degree days to 400 days from 319 days in 2011 slightly offset by an 11% decrease in the number of heating degree days to 455 days from 513 days in 2011. Although DP&L had a number of customers that switched their retail electric service from DP&L to DPLER, an affiliated CRES provider, DP&L continued to provide distribution services to those customers within its service territory. The average retail rates decreased 3% overall primarily as a result of customers switching from DP&L to DPLER. The remaining distribution services provided by DP&L were billed at a lower rate resulting in a reduction of total average retail rates. The decrease in average retail rates resulting from customers switching was partially offset by the implementation of the fuel and energy efficiency riders, increased TCRR and RPM riders, and the incremental effect of the recovery of costs under the EIR. The above resulted in an unfavorable $13.7 million retail sales volume variance and an unfavorable $5.4 million retail price variance. |
· | Wholesale revenues decreased $8.9 million primarily as a result of a 7% decrease in wholesale sales volume which was largely a result of lower generation by our power plants, as well as a 2% decrease in wholesale average prices partially offset by the effect of customer switching discussed in the immediately preceding paragraph. DP&L records wholesale revenues from its sale of transmission and generation services to DPLER associated with these switched customers. This resulted in an unfavorable $6.9 million wholesale volume variance and a $2.0 million unfavorable wholesale price variance. |
· | RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, decreased $19.2 million compared to the same period in 2011. This decrease in RTO capacity and other revenues was primarily the result of a $19.5 million decrease in revenues realized from the PJM capacity auction, offset by a slight increase of $0.3 million in transmission and congestion revenues. |
For the six months ended June 30, 2012, Revenues decreased $100.5 million, or 12%, to $746.2 million from $846.7 million in the prior year. This decrease was primarily the result of lower average retail rates, lower retail and wholesale sales volumes and decreased RTO capacity and other revenues, partially offset by higher average wholesale prices. The revenue components for the six months ended June 30, 2012 are further discussed below:
· | Retail revenues decreased $53.0 million primarily due to a 9% decrease in retail sales volumes compared to those in the prior year largely due to unfavorable weather conditions. The unfavorable weather conditions resulted in a 22% decrease in the number of heating degree days to 2,718 days from 3,480 days in 2011 offset slightly by a 35% increase in the number of cooling degree days to 430 days from 319 days in 2011. Although DP&L had a number of customers that switched their retail electric service from DP&L to DPLER, an affiliated CRES provider, DP&L continued to provide distribution services to those customers within its service territory. The average retail rates decreased 2% overall primarily as a result of customers switching from DP&L to DPLER. The remaining distribution services provided by DP&L were billed at a lower rate resulting in a reduction of total average retail rates. The decrease in average retail rates resulting |
from customers switching was partially offset by the implementation of the fuel and energy efficiency riders, increased TCRR and RPM riders, and the incremental effect of the recovery of costs under the EIR. The above resulted in an unfavorable $44.1 million retail sales volume variance and an unfavorable $8.8 million retail price variance.
· | Wholesale revenues decreased $10.6 million primarily as a result of a 7% decrease in wholesale sales volume which was largely a result of lower generation by our power plants, partially offset by the effect of customer switching discussed in the immediately preceding paragraph. DP&L records wholesale revenues from its sale of transmission and generation services to DPLER associated with these switched customers. This decrease was partially offset by a 2% increase in average wholesale sales prices. This resulted in an unfavorable $14.4 million wholesale volume variance offset partially by a $3.8 million favorable wholesale price variance. |
RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, decreased $37.7 million compared to the same period in 2011. This decrease in RTO capacity and other revenues was primarily the result of a $34.9 million decrease in revenues realized from the PJM capacity auction and a decrease of $2.8 million in transmission and congestion revenues.
DP&L – Cost of Revenues
For the three months ended June 30, 2012:
· | Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $20.5 million, or 23%, during the quarter ended June 30, 2012 compared to the same period in 2011. This decrease was largely due to an $18.3 million decrease in fuel costs driven by a 22% decrease in the volume of generation at our plants. Also contributing to this decrease were unrealized MTM gains of $1.9 million for the three months ended June 30, 2012 versus $3.3 million MTM losses during the same period in 2011. Partially offsetting the decreases were $1.9 million in realized losses from DP&L’s sale of coal, compared to $1.1 million of realized gains during the same period in 2011. |
· | Net purchased power decreased $35.1 million, or 34%, compared to the same period in 2011 due largely to a $30.2 million decrease in RTO capacity and other charges which were incurred as a member of PJM, including costs associated with DP&L’s load obligations for retail customers. This decrease included the net impact of the deferral and recovery of DP&L’s transmission, capacity and other PJM-related charges. Purchased power volumes increased 56% while purchased power prices decreased approximately 39% resulting in a decrease of $1.7 million compared to the same period in 2011. We purchase power to satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages or when market prices are below the marginal costs associated with our generating facilities. |
For the six months ended June 30, 2012:
· | Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $23.5 million, or 13%, during the six months ended June 30, 2012 compared to the same period in 2011. This decrease was largely due to a $29.3 million decrease in fuel costs driven by an 18% decrease in the volume of generation at our plants. Also contributing to the decrease were unrealized MTM losses of $1.5 million for the six months ended June 30, 2012 versus $3.9 million MTM losses during the same period in 2011. Partially offsetting the decreases were $5.3 million in realized losses from DP&L’s sale of coal, compared to $2.9 million of realized gains during the same period in 2011. |
· | Net purchased power decreased $68.0 million, or 31%, compared to the same period in 2011 due largely to a $58.2 million decrease in RTO capacity and other charges which were incurred as a member of PJM, including costs associated with DP&L’s load obligations for retail customers. This decrease included the net impact of the deferral and recovery of DP&L’s transmission, capacity and other PJM-related charges. Purchased power volumes increased 13% while purchased power prices decreased approximately 25% resulting in a decrease of $10.1 million compared to the same period in 2011. We purchase power to |
satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages or when market prices are below the marginal costs associated with our generating facilities.
DP&L – Operation and Maintenance
Three Months Ended June 30, 2012 vs. 2011 | Six Months Ended June 30, 2012 vs. 2011 | |||||||
($ in millions) | ||||||||
Low-income payment program(1) | $ | 5.2 | $ | 10.4 | ||||
Generating facilities operating and maintenance expenses | — | 1.4 | ||||||
Pension expenses | 0.6 | 1.7 | ||||||
Maintenance of overhead transmission and distribution lines | (0.6 | ) | (6.3 | ) | ||||
Deferred compensation | (1.8 | ) | (2.0 | ) | ||||
Other, net | (2.5 | ) | 3.5 | |||||
Total operation and maintenance expense | $ | 0.9 | $ | 8.7 |
(1) | There is a corresponding increase in Revenues associated with this program resulting in no impact to Net income. |
For the three months ended June 30, 2012, Operation and maintenance expense increased $0.9 million, or 1%, compared to the same period in 2011. This variance was primarily the result of increased assistance for low-income retail customers which is funded by the USF revenue rate rider. These increases were partially offset by decreased expenses related to deferred compensation arrangements primarily related to fewer equity awards in the current periods.
For the six months ended June 30, 2012, Operation and maintenance expense increased $8.7 million, or 5%, compared to the same period in 2011. This variance was primarily the result of:
· | increased assistance for low-income retail customers which is funded by the USF revenue rate rider, |
· | increased expenses for generating facilities largely due to the length and timing of planned outages at jointly owned production units relative to the same period in 2011, and |
· | increased pension expenses primarily related to changes in plan assumptions, specifically a lower discount rate and lower expected rate of return on plan assets. |
These increases were partially offset by:
· | decreased expenses related to the maintenance of overhead transmission and distribution lines primarily as a result of storms, including a significant ice storm in February 2011, and |
· | decreased expenses related to deferred compensation arrangements primarily related to fewer equity awards in the current periods. |
DP&L – Depreciation and Amortization
For the three and six months ended June 30, 2012, Depreciation and amortization expense increased $2.7 million and $4.3 million, respectively, as compared to 2011. The increase primarily reflected the impact of investments in plant and equipment during the six months ended June 30, 2012.
DP&L – General Taxes
For the three and six months ended June 30, 2012, General taxes increased $0.5 million, or 3%, and $1.1 million, or 3%, respectively, as compared to 2011. This increase was primarily the result of higher property tax accruals in 2012. Prior to the Merger date, certain excise and other taxes were recorded gross. Effective on the
Merger date, these taxes are accounted for on a net basis and are recorded as a reduction in Revenues for presentation in accordance with AES policy. The 2011 amounts were reclassified to conform to this presentation.
DP&L – Interest Expense
Interest expense recorded during the three and six months ended June 30, 2012 did not fluctuate significantly from that recorded during the three and six months ended June 30, 2011.
DP&L – Income Tax Expense
For the three and six months ended June 30, 2012, Income tax expense increased $0.1 million, or 1%, and decreased $9.6 million, or 23%, respectively, as compared to 2011 primarily due to decreased pre-tax income during the six month period.
Financial Condition, Liquidity and Capital Requirements
DPL’s financial condition, liquidity and capital requirements include the consolidated results of its principal subsidiary DP&L. All material intercompany accounts and transactions have been eliminated in consolidation. The following table provides a summary of the cash flows for DPL and DP&L:
DPL
Combined | Successor | Predecessor | ||||||||||||||||||
Year ended December 31, 2011 | November 28, 2011 through December 31, 2011 | January 1, 2011 through November 27, 2011 | Years ended December 31, | |||||||||||||||||
2010 | 2009 | |||||||||||||||||||
($ in millions) | ||||||||||||||||||||
Net cash provided by operating activities | $ | 324.6 | $ | (0.9 | ) | $ | 325.5 | $ | 464.2 | $ | 524.7 | |||||||||
Net cash used for investing activities | (142.7 | ) | (30.9 | ) | (111.8 | ) | (220.6 | ) | (164.7 | ) | ||||||||||
Net cash used for financing activities | (151.6 | ) | 88.9 | (240.5 | ) | (194.5 | ) | (347.6 | ) | |||||||||||
Net change | 30.3 | 57.1 | (26.8 | ) | 49.1 | 12.4 | ||||||||||||||
Assumption of cash at acquisition | 19.2 | 19.2 | - | - | - | |||||||||||||||
Cash and cash equivalents at beginning of period | 124.0 | 97.2 | 124.0 | 74.9 | 62.5 | |||||||||||||||
Cash and cash equivalents at end of period | $ | 173.5 | $ | 173.5 | $ | 97.2 | $ | 124.0 | $ | 74.9 |
Six months ended June 30, | ||||||||
2012 Successor | 2011 Predecessor | |||||||
($ in millions) | ||||||||
Net cash provided by operating activities | $ | 143.1 | $ | 185.1 | ||||
Net cash used for investing activities | (110.5 | ) | (28.6 | ) | ||||
Net cash used for financing activities | (53.8 | ) | (207.7 | ) | ||||
Net change | (21.2 | ) | (51.2 | ) | ||||
Cash and cash equivalents at beginning of period | 173.5 | 124.0 | ||||||
Cash and cash equivalents at end of period | $ | 152.3 | $ | 72.8 |
DP&L
Years ended December 31, | ||||||||||||
2011 | 2010 | 2009 | ||||||||||
($ in millions) | ||||||||||||
Net cash provided by operating activities | $ | 355.8 | $ | 446.4 | $ | 513.7 | ||||||
Net cash used for investing activities | (176.6 | ) | (148.6 | ) | (166.0 | ) | ||||||
Net cash used for financing activities | (201.0 | ) | (300.9 | ) | (311.4 | ) | ||||||
Net change | (21.8 | ) | (3.1 | ) | 36.3 | |||||||
Cash and cash equivalents at beginning of period | 54.0 | 57.1 | 20.8 | |||||||||
Cash and cash equivalents at end of period | $ | 32.2 | $ | 54.0 | $ | 57.1 |
For the Six Months Ended June 30, | ||||||||
2012 | 2011 | |||||||
($ in millions) | ||||||||
Net cash provided by operating activities | $ | 173.5 | $ | 163.2 | ||||
Net cash used for investing activities | (109.5 | ) | (89.1 | ) | ||||
Net cash used for financing activities | (70.5 | ) | (115.4 | ) | ||||
Net change | (6.5 | ) | (41.3 | ) | ||||
Cash and cash equivalents at beginning of period | 32.2 | 54.0 | ||||||
Cash and cash equivalents at end of period | $ | 25.7 | $ | 12.7 |
The significant items that have impacted the cash flows for DPL and DP&L are discussed in greater detail below:
DPL – Net Cash provided by Operating Activities
The revenue from our energy business continues to be the principal source of cash from operating activities while our primary uses of cash include payments for fuel, purchased power, operation and maintenance expenses, interest and taxes.
DPL’s Net cash provided by operating activities for the years ended December 31, 2011, 2010 and 2009 can be summarized as follows:
Combined | Successor | Predecessor | ||||||||||||||||||
Year ended December 31, 2011 | November 28, 2011 through December 31, 2011 | January 1, 2011 through November 27, 2011 | Years ended December 31, | |||||||||||||||||
2010 | 2009 | |||||||||||||||||||
($ in millions) | ||||||||||||||||||||
Earnings from continuing operations | $ | 144.3 | $ | (6.2 | ) | $ | 150.5 | $ | 290.3 | $ | 229.1 | |||||||||
Depreciation and amortization | 152.6 | 23.2 | 129.4 | 139.4 | 145.5 | |||||||||||||||
Deferred income taxes | 65.6 | 0.1 | 65.5 | 59.9 | 201.6 | |||||||||||||||
Charge for early redemption of debt | 15.3 | — | 15.3 | — | — | |||||||||||||||
Contribution to pension plan | (40.0 | ) | — | (40.0 | ) | (40.0 | ) | — | ||||||||||||
Deferred regulatory costs, net | (14.3 | ) | 0.1 | (14.4 | ) | 21.8 | (23.6 | ) | ||||||||||||
Cash settlement of interest rate hedges, net of tax | (31.3 | ) | — | (31.3 | ) | — | — | |||||||||||||
Other | 32.4 | (18.1 | ) | 50.5 | (7.2 | ) | (27.9 | ) | ||||||||||||
Net cash provided by operating activities | $ | 324.6 | $ | (0.9 | ) | $ | 325.5 | $ | 464.2 | $ | 524.7 |
For the year ended December 31, 2011, Net cash provided by operating activities was primarily a result of Earnings from continuing operations adjusted for noncash depreciation and amortization, combined with the following significant transactions:
· | The $65.6 million increase to Deferred income taxes primarily results from changes related to pension contributions, depreciation expense and repair expense. |
· | A $15.3 million charge for the early redemption of DPL Capital Trust II securities. |
· | DP&L made discretionary contributions of $40.0 million to the defined benefit pension plan in 2011. |
· | DPL made a cash payment of $48.1 million ($31.3 million net of the tax effect) related to interest rate hedge contracts that settled during the period. |
· | Other represents items that had a current period cash flow impact and includes changes in working capital and other future rights or obligations to receive or to pay cash. These items are primarily impacted by, among other factors, the timing of when cash payments are made for fuel, purchased power, operating costs, interest and taxes, and when cash is received from our utility customers and from the sales of coal and excess emission allowances. |
For the year ended December 31, 2010, Net cash provided by operating activities was primarily a result of Earnings from continuing operations adjusted for noncash depreciation and amortization, combined with the following significant transactions:
· | The $59.9 million increase to Deferred income taxes primarily results from changes related to pension contributions, depreciation expense and repair expense. |
· | DP&L made discretionary contributions of $40.0 million to the defined benefit pension plan in 2010. |
· | $21.8 million of cash collected to pay for fuel, purchased power and other fuel related costs and transmission, capacity and other PJM-related costs incurred during 2010, in excess of cash expenditures. These costs reduced the Regulatory asset in accordance with the provisions of GAAP relating to regulatory accounting (see Note 4 of Notes to DPL’s Consolidated Financial Statements) and are expected to reduce the amount to be collected from customers in future periods. |
· | Other represents items that had a current period cash flow impact and includes changes in working capital and other future rights or obligations to receive or to pay cash. These items are primarily impacted by, among other factors, the timing of when cash payments are made for fuel, purchased power, operating costs, interest and taxes, and when cash is received from our utility customers and from the sales of coal and excess emission allowances. |
For the year ended December 31, 2009, Net cash provided by operating activities was primarily a result of Earnings from continuing operations adjusted for noncash depreciation and amortization, combined with the following significant transactions:
· | The $201.6 million increase to Deferred income taxes primarily results from the recognition of certain tax benefits for 2008 and 2009 relating to a change in the tax accounting method for deductions pertaining to repairs, depreciation and mixed service costs. Primarily due to the recognition of these benefits during 2009, DPL received a net cash refund of state and federal income taxes totaling $94.6 million and, in addition, was able to offset $69.0 million of these benefits against income tax liabilities accrued in 2009. |
· | $23.6 million of cash used primarily to pay for transmission, capacity and other PJM-related costs incurred during 2009, net of recoveries. These costs were recorded as a Regulatory asset in accordance with the provisions of GAAP relating to regulatory accounting (see Note 4 of Notes to DPL’s Consolidated Financial Statements) and are expected to be collected from customers during future years. |
· | Other represents items that had a current period cash flow impact and includes changes in working capital and other future rights or obligations to receive or to pay cash. These items are primarily impacted by, among other factors, the timing of when cash payments are made for fuel, purchased power, operating costs, interest and taxes, and when cash is received from our utility customers and from the sales of coal and excess emission allowances. |
DPL’s Net cash provided by operating activities for the six months ended June 30, 2012 and 2011 can be summarized as follows:
Successor | Predecessor | ||||||||
Six months ended June 30, 2012 | Six months ended June 30, 2011 | ||||||||
($ in millions) | |||||||||
Net income | $ | 33.6 | $ | 75.2 | |||||
Depreciation and amortization | 100.0 | 70.2 | |||||||
Deferred income taxes | (3.1 | ) | 37.5 | ||||||
Charge for early redemption of debt | — | 15.3 | |||||||
Contribution to pension plan | — | (40.0 | ) | ||||||
Accrued interest | 1.5 | 2.0 | |||||||
Deferred regulatory costs, net | 0.1 | 8.9 | |||||||
Other | 11.0 | 16.0 | |||||||
Net cash provided by operating activities | $ | 143.1 | $ | 185.1 |
For the six months ended June 30, 2012, Net cash provided by operating activities was primarily a result of Net income adjusted for noncash depreciation and amortization. Other represents items that had a current period cash flow impact and includes changes in working capital and other future rights or obligations to receive or to pay cash. These items are primarily impacted by, among other factors, the timing of when cash payments are made for fuel, purchased power, operating costs, taxes, and when cash is received from our utility customers and from the sales of coal and excess emission allowances. Accrued interest relates primarily to the $1,250.0 million of debt and the timing of payments.
For the six months ended June 30, 2011, Net cash provided by operating activities was primarily a result of earnings from continuing operations adjusted for noncash depreciation and amortization, combined with the following significant transactions:
· | A $37.5 million increase to Deferred income taxes primarily as a result of depreciation as well as pension contributions. |
· | A $15.3 million charge for the early redemption of DPL Capital Trust II securities. |
· | A DP&L contribution of $40.0 million to the defined benefit pension plan in February 2011. |
DP&L – Net Cash provided by Operating Activities
DP&L’s Net cash provided by operating activities for the years ended December 31, 2011, 2010 and 2009 are summarized as follows:
2011 | 2010 | 2009 | ||||||||||
($ in millions) | ||||||||||||
Net income | $ | 193.2 | $ | 277.7 | $ | 258.9 | ||||||
Depreciation and amortization | 134.9 | 130.7 | 135.5 | |||||||||
Deferred income taxes | 50.7 | 54.3 | 200.1 | |||||||||
Contribution to pension plan | (40.0 | ) | (40.0 | ) | - | |||||||
Deferred regulatory costs, net | (12.6 | ) | 21.8 | (23.6 | ) | |||||||
Other | 29.6 | 1.9 | (57.2 | ) | ||||||||
Net cash provided by operating activities | $ | 355.8 | $ | 446.4 | $ | 513.7 |
For the years ended December 31, 2011, 2010 and 2009, the significant components of DP&L’s Net cash provided by operating activities are similar to those discussed under DPL’s Net cash provided by operating activities above.
DP&L’s Net cash provided by operating activities for the six months ended June 30, 2012 and 2011 can be summarized as follows:
Six Months Ended June 30 | ||||||||
2012 | 2011 | |||||||
($ in millions) | ||||||||
Net income | $ | 69.4 | $ | 83.5 | ||||
Depreciation and amortization | 70.8 | 66.5 | ||||||
Deferred income taxes | 3.3 | 37.2 | ||||||
Contribution to pension plan | — | (40.0 | ) | |||||
Accrued interest | 5.2 | 5.3 | ||||||
Deferred regulatory costs, net | (0.1 | ) | 8.9 | |||||
Other | 24.9 | 1.8 | ||||||
Net cash provided by operating activities | $ | 173.5 | $ | 163.2 |
For the six months ended June 30, 2012 and 2011, the significant components of DP&L’s Net cash provided by operating activities are similar to those discussed under DPL’s Net cash provided by operating activities above.
DPL – Net Cash (used for) provided by Investing Activities
DPL’s Net cash used for investing activities for the years ended December 31, 2011, 2010 and 2009 are summarized as follows:
Combined | Successor | Predecessor | ||||||||||||||||||
Year ended December 31, 2011 | November 28, 2011 through December 31, 2011 | January 1, 2011 through November 27, 2011 | Years ended December 31, | |||||||||||||||||
2010 | 2009 | |||||||||||||||||||
($ in millions) | ||||||||||||||||||||
Environmental and renewable energy capital expenditures | $ | (11.8 | ) | $ | - | $ | (11.8 | ) | $ | (11.9 | ) | $ | (21.2 | ) | ||||||
Other plant-related asset acquisitions | (192.9 | ) | (30.5 | ) | (162.4 | ) | (140.8 | ) | (151.1 | ) | ||||||||||
Purchase of MC Squared | (8.3 | ) | — | (8.3 | ) | — | — | |||||||||||||
Sales / (purchases) of short-term investments | 69.2 | — | 69.2 | (69.3 | ) | 5.0 | ||||||||||||||
Other | 1.1 | (0.4 | ) | 1.5 | 1.4 | 2.6 | ||||||||||||||
DPL’s net cash used for investing activities | $ | (142.7 | ) | $ | (30.9 | ) | $ | (111.8 | ) | $ | (220.6 | ) | $ | (164.7 | ) |
For the year ended December 31, 2011, DP&L’s environmental expenditures were primarily related to pollution control devices at our generation plants. Additionally, DPL, on behalf of DPLER, made a cash payment of approximately $8.3 million to acquire MC Squared (see Note 19 of Notes to DPL’s Consolidated Financial Statements). Additionally, DPL redeemed $70.9 million of short-term investments mostly comprised of VRDN securities and purchased an additional $1.7 million of short-term investments during the same period. The VRDN securities have variable coupon rates that are typically re-set weekly relative to various short-term rate indices. DPL can tender these securities for sale upon notice to the broker and receive payment for the tendered securities within seven days.
For the year ended December 31, 2010, DP&L continued to see reductions in its environmental capital expenditures due to the completion of FGD and SCR projects including the FGD and SCR equipment completed and placed into service at Conesville during the fourth quarter of 2009. Approximately $4.2 million of the environmental capital expenditures incurred during 2010 relate to the construction of a solar energy facility at Yankee station. DP&L also continued to make upgrades and other investments in other generation, transmission and distribution equipment. Additionally, DPL purchased $54.2 million of VRDN securities, net of redemptions from various institutional securities brokers as well as $15.1 million of investment-grade fixed income corporate bonds. The VRDN securities are backed by irrevocable letters of credit. These securities have variable coupon rates that are typically re-set weekly relative to various short-term rate indices. DPL can tender these VRDN securities for sale upon notice to the broker and receive payment for the tendered securities within seven days.
For the year ended December 31, 2009, DP&L continued to see reductions in its environmental-related capital expenditures due to the completion of FGD and SCR projects. The expenditures in 2009 relate to the construction of FGD and SCR equipment at the Conesville generation station which was substantially completed and placed into service during the fourth quarter of 2009. DP&L also continued to make upgrades and other investments in other generation, transmission and distribution equipment.
DPL’s Net cash used for investing activities for the six months ended June 30, 2012 and 2011 can be summarized as follows:
Successor | Predecessor | ||||||||
Six months ended June 30, 2012 | Six months ended June 30, 2011 | ||||||||
($ in millions) | |||||||||
Other plant-related asset acquisitions, net | $ | (104.9 | ) | $ | (85.5 | ) | |||
Environmental and renewable energy capital expenditures | (5.6 | ) | (5.9 | ) | |||||
Purchase of MC Squared | — | (8.2 | ) | ||||||
Sales/(purchases) of short-term investments, net | — | 69.2 | |||||||
Other | — | 1.8 | |||||||
Net cash (used for) / provided by investing activities | $ | (110.5 | ) | $ | (28.6 | ) |
For the six months ended June 30, 2012, DPL’s cash used for investing activities reflects assets acquired at our generation plants.
For the six months ended June 30, 2011, DPL cash used for investing activities was primarily for assets acquired at our generation plants. Additionally, DPL, on behalf of DPLER, made a cash payment of approximately $8.2 million to acquire MC Squared. Also during the six months ended June 30, 2011, DPL redeemed $70.9 million of short-term investments mostly comprised of VRDN securities as well as purchased an additional $1.7 million of short-term investments during the same period. These securities have variable coupon rates that are typically re-set weekly relative to various short-term rate indices. DPL can tender these VRDN securities for sale upon notice to the broker and receive payment for the tendered securities within seven days.
DP&L – Net Cash used for Investing Activities
DP&L’s Net cash used for investing activities for the years ended December 31, 2011, 2010 and 2009 are summarized as follows:
2011 | 2010 | 2009 | ||||||||||
($ in millions) | ||||||||||||
Environmental and renewable energy capital expenditures | $ | (11.8 | ) | $ | (11.9 | ) | $ | (21.2 | ) | |||
Other plant-related asset acquisitions | (192.7 | ) | (138.1 | ) | (146.2 | ) | ||||||
Proceeds from liquidation of DPL stock, held in trust | 26.9 | — | — | |||||||||
Other | 1.0 | 1.4 | 1.4 | |||||||||
DP&L’s net cash used for investing activities | $ | (176.6 | ) | $ | (148.6 | ) | $ | (166.0 | ) |
For the year ended December 31, 2011, DP&L’s environmental expenditures were primarily related to pollution control devices at our generation plants. Additionally, DP&L received proceeds of $26.9 million related to the liquidation of DPL stock held in the Master Trust.
For the year ended December 31, 2010, DP&L continued to see reductions in its environmental capital expenditures due to the completion of FGD and SCR projects including the FGD and SCR equipment completed and placed into service at Conesville during the fourth quarter of 2009. Approximately $4.2 million of the environmental capital expenditures incurred during 2010 relate to the construction of a solar energy facility at Yankee station. DP&L also continued to make upgrades and other investments in other generation, transmission and distribution equipment.
For the year ended December 31, 2009, DP&L continued to see reductions in its environmental-related capital expenditures due to the completion of FGD and SCR projects. The expenditures in 2009 relate to the construction of FGD and SCR equipment at the Conesville generation station which was substantially completed and placed into service during the fourth quarter of 2009. DP&L also continued to make upgrades and other investments in other generation, transmission and distribution equipment.
DP&L’s Net cash used for investing activities for the six months ended June, 2012 and 2011 can be summarized as follows:
Six Months Ended June 30, | ||||||||
2012 | 2011 | |||||||
($ in millions) | ||||||||
Other plant-related asset acquisitions, net | $ | (103.9 | ) | $ | (85.0 | ) | ||
Environmental and renewable energy capital expenditures | (5.6 | ) | (5.8 | ) | ||||
Other | — | 1.7 | ||||||
Net cash used for investing activities | $ | (109.5 | ) | $ | (89.1 | ) |
For the six months ended June 30, 2012 and 2011, the significant components of DP&L’s Net cash used for investing activities are similar to those discussed under DPL’s Net cash used for investing activities above with the exception of the short-term investing activity.
DPL – Net Cash used for Financing Activities
DPL’s Net cash used for financing activities for the years ended December 31, 2011, 2010 and 2009 can be summarized as follows:
Combined | Successor | Predecessor | ||||||||||||||||||
Year ended December 31, 2011 | November 28, 2011 through December 31, 2011 | January 1, 2011 through November 27, 2011 | Years ended December 31, | |||||||||||||||||
2010 | 2009 | |||||||||||||||||||
($ in millions) | ||||||||||||||||||||
Dividends paid on common stock | $ | (176.0 | ) | $ | (63.0 | ) | $ | (113.0 | ) | $ | (139.7 | ) | $ | (128.8 | ) | |||||
Retirement of long-term debt | (297.5 | ) | — | (297.5 | ) | — | (175.0 | ) | ||||||||||||
Early redemption of long-term debt, including premium | (134.2 | ) | — | (134.2 | ) | — | (56.1 | ) | ||||||||||||
Payment of MC Squared debt | (13.5 | ) | — | (13.5 | ) | — | - | |||||||||||||
Repurchase of DPL common stock | — | — | — | (56.4 | ) | (64.4 | ) | |||||||||||||
Repurchase of warrants | — | — | — | — | (25.2 | ) | ||||||||||||||
Issuance of long-term debt | 425.0 | 125.0 | 300.0 | — | — | |||||||||||||||
Proceeds from liquidation of DPL stock, held in trust | 26.9 | 26.9 | — | — | — | |||||||||||||||
Proceeds from exercise of warrants | 14.7 | — | 14.7 | — | 77.7 | |||||||||||||||
Cash withdrawn from restricted funds | — | — | — | — | 14.5 | |||||||||||||||
Other | 3.0 | — | 3.0 | 1.6 | 9.7 | |||||||||||||||
Net cash used for financing activities | $ | (151.6 | ) | $ | 88.9 | $ | (240.5 | ) | $ | (194.5 | ) | $ | (347.6 | ) |
For the year ended December 31, 2011, DPL paid common stock dividends of $176.0 million and retired long-term debt of $297.5 million. Additionally, DPL paid $134.2 million for its purchase of a portion of the DPL Capital Trust II capital securities, of which $122.0 million related to the capital securities and an additional $12.2 million related to the premium paid on the purchase. DPL also paid down the debt of MC Squared which was acquired in February 2011 (see Note 19 of Notes to DPL’s Consolidated Financial Statements). DPL received $425.0 million from the issuance of additional debt. DPL received $26.9 million upon the liquidation of DPL stock held in the DP&L Master Trust and $14.7 million from the exercise of 700,000 warrants.
For the year ended December 31, 2010, DPL paid common stock dividends of $139.7 million. In addition, under the stock repurchase programs approved by the Board of Directors in October 2009 and October 2010 (see Note 14 of Notes to DPL’s Consolidated Financial Statements), DPL repurchased approximately 2.18 million DPL common shares for $56.4 million.
For the year ended December 31, 2009, DPL redeemed long-term debt totaling $227.4 million and paid common stock dividends of $128.8 million. Under a stock repurchase program approved by the Board of Directors in October 2009 (see Note 14 of Notes to DPL’s Consolidated Financial Statements), DPL repurchased approximately 2.4 million DPL common shares for $64.4 million. In addition, DPL repurchased 8.6 million warrants for $25.2 million. DPL’s cash inflows during the period include $77.7 million received from the cash exercise of 3.7 million warrants and the withdrawal of the remaining balance of restricted funds of $14.5 million which was used primarily to fund the construction of FGD equipment at the Conesville generation station. DPL also received $9.0 million from option holders who exercised stock options.
DPL’s Net cash used for financing activities for the six months ended June 30, 2012 and 2011 can be summarized as follows:
Successor | Predecessor | ||||||||
Six Months Ended June 30, 2012 | Six Months Ended June 30, 2011 | ||||||||
($ in millions) | |||||||||
Dividends paid on common stock | $ | (45.0 | ) | $ | (76.4 | ) | |||
Contributions to additional paid-in capital from parent | 0.3 | — | |||||||
Payment to former warrant holders | (9.0 | ) | — | ||||||
Retirement of long-term debt | (0.1 | ) | — | ||||||
Early redemption of long-term debt, including premium | — | (134.2 | ) | ||||||
Payment of MC Squared debt | — | (13.5 | ) | ||||||
Exercise of warrants | — | 14.7 | |||||||
Exercise of stock options including tax impact | — | 1.7 | |||||||
Net cash used for financing activities | $ | (53.8 | ) | $ | (207.7 | ) |
For the six months ended June 30, 2012, DPL paid common stock dividends of $45.0 million to its parent, partially offset by contributions to additional paid-in capital from its parent, AES. DPL also paid $9.0 million to former warrant holders which represents the difference between the exercise price of $21.00 per share and the $30.00 per share paid by AES in the Merger.
For the six months ended June 30, 2011, DPL paid common stock dividends of $76.4 million and paid $134.2 million for the purchase of the DPL Capital Trust II capital securities, of which $122.0 million related to the capital securities and an additional $12.2 million related to the premium paid on the purchase. DPL also paid down the debt of MC Squared which was acquired in February 2011.
DP&L – Net Cash used for Financing Activities
DP&L’s Net cash used for financing activities for the years ended December 31, 2011, 2010 and 2009 can be summarized as follows:
2011 | 2010 | 2009 | ||||||||||
($ in millions) | ||||||||||||
Dividends paid on common stock to parent | $ | (220.0 | ) | $ | (300.0 | ) | $ | (325.0 | ) | |||
Cash contribution from parent | 20.0 | — | — | |||||||||
Cash withdrawn from restricted funds | — | — | 14.5 | |||||||||
Other | (1.0 | ) | (0.9 | ) | (0.9 | ) | ||||||
Net cash used for financing activities | $ | (201.0 | ) | $ | (300.9 | ) | $ | (311.4 | ) |
For the year ended December 31, 2011, DP&L’s Net cash used for financing activities primarily relates to $220 million in dividends offset by $20 million of additional capital contributed by DPL.
For the year ended December 31, 2010, DP&L’s Net cash used for financing activities primarily relates to $300 million in dividends.
For the year ended December 31, 2009, DP&L paid $325 million in dividends to DPL and withdrew the remaining balance of $14.5 million from restricted funds to pay for the Conesville FGD and SCR projects.
DP&L’s Net cash used for financing activities for the six months ended June 30, 2012 and 2011 can be summarized as follows:
Six Months Ended June 30, | ||||||||
2012 | 2011 | |||||||
($ in millions) | ||||||||
Dividends paid on common stock to parent | $ | (70.0 | ) | $ | (115.0 | ) | ||
Other | (0.5 | ) | (0.4 | ) | ||||
Net cash used for financing activities | $ | (70.5 | ) | $ | (115.4 | ) |
For the six months ended June 30, 2012, DP&L’s Net cash used for financing activities primarily relates to $70.0 million in dividends paid to DPL.
For the six months ended June 30, 2011, DP&L’s Net cash used for financing activities primarily relates to $115.0 million in dividends paid to DPL.
Liquidity
We expect our existing sources of liquidity to remain sufficient to meet our anticipated operating needs. Our business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and carrying costs, potential margin requirements for retail operations, and dividend payments. For 2012, and in subsequent years, we expect to satisfy these requirements with a combination of cash from operations and funds from the capital markets as our internal liquidity needs and market conditions warrant. We also expect that the borrowing capacity under bank credit facilities will continue to be available to manage working capital requirements during those periods.
As of July 31, 2012, DP&L has access to $400.0 million of short-term financing under two revolving credit facilities. The first facility, established in August 2011, is for $200.0 million, expires in August 2015 and has eight participating banks, with no bank having more than 22% of the total commitment. DP&L also has the option to increase the potential borrowing amount under the first facility by $50.0 million. The second facility, established in April 2010, is for $200.0 million and expires in April 2013. A total of five banks participate in this facility, with no bank having more than 35% of the total commitment. DP&L also has the option to increase the potential borrowing amount under the second facility by $50.0 million.
As of July 31, 2012, DPL has access to $125.0 million of short-term financing under a revolving credit facility established in August 2011. This facility expires in August 2014 and has seven participating banks with no bank having more than 32% of the total commitment.
Type | Maturity | Commitment | Amounts available as of June 30, 2012 | ||||||||
($ in millions) | |||||||||||
DP&L | Revolving | August 2015 | $ | 200.0 | $ | 200.0 | |||||
DP&L | Revolving | April 2013 | 200.0 | 200.0 | |||||||
DPL Inc. | Revolving | August 2014 | 125.0 | 125.0 | |||||||
$ | 525.0 | $ | 525.0 |
Each DP&L revolving credit facility has a $50.0 million letter of credit sublimit. The entire DPL revolving credit facility amount is available for letter of credit issuances. As of June 30, 2012 and through July 31, 2012, there were no letters of credit issued and outstanding on the revolving credit facilities.
Cash and cash equivalents for DPL and DP&L amounted to $152.3 million and $25.7 million, respectively, at June 30, 2012. At that date, neither DPL nor DP&L had any short-term investments that were not included in cash and cash equivalents.
On February 23, 2011, DPL purchased and retired $122.0 million principal amount of DPL Capital Trust II 8.125% trust preferred securities. As part of this transaction, DPL paid a $12.2 million, or 10%, premium. Debt issuance costs and unamortized debt discount associated with this transaction, totaling $3.1 million, were also recognized in February 2011.
Capital Requirements
Planned construction additions for 2012 relate primarily to new investments in and upgrades to DP&L’s power plant equipment and transmission and distribution system. Capital projects are subject to continuing review and are revised in light of changes in financial and economic conditions, load forecasts, legislative and regulatory developments and changing environmental standards, among other factors.
DPL, through its subsidiary DP&L, is projecting to spend an estimated $585.0 million in capital projects for the period 2012 through 2014. Approximately $15.0 million of this projected amount is to enable DP&L to meet the recently revised reliability standards of NERC. DP&L is subject to the mandatory reliability standards of NERC and Reliability First Corporation (RFC), one of the eight NERC regions, of which DP&L is a member. NERC has changed the definition of the Bulk Electric System (BES) to include 100 kV and above facilities, thus expanding the facilities to which the reliability standards apply. DP&L’s 138 kV facilities were previously not subject to these reliability standards. Accordingly, DP&L anticipates spending approximately $72.0 million within the next 5 years to reinforce its 138 kV system to comply with these new NERC standards. Our ability to complete capital projects and the reliability of future service will be affected by our financial condition, the availability of internal funds and the reasonable cost of external funds. We expect to finance our construction additions with a combination of cash on hand, short-term financing, long-term debt and cash flows from operations.
Debt Covenants
As mentioned above, DPL has access to $125.0 million of short-term financing under its revolving credit facility and has borrowed $425.0 million under its term loan facility. Each of these facilities has two financial covenants. The first financial covenant requires DPL’s total debt to total capitalization ratio to not exceed 0.70 to 1.00. The second financial covenant requires DPL’s consolidated earnings before interest, taxes, depreciation and amortization (EBITDA) to consolidated interest charge ratio to be not less than 2.50 to 1.00. As of June 30, 2012 the first covenant was met with a ratio of 0.55 to 1.00, and the second covenant was met with a ratio of 5.20 to 1.00. The debt to capitalization ratio is calculated as the sum of DPL’s current and long-term portion of debt, including its guarantee obligations, divided by the total of DPL’s shareholder’s equity and total debt including guarantee obligations. The consolidated interest rate coverage ratio is calculated, at the end of each fiscal quarter, by dividing consolidated EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period.
Also mentioned above, DP&L has access to $400.0 million of short-term financing under its two revolving credit facilities. The following financial covenant is contained in each revolving credit facility: DP&L’s total debt to total capitalization ratio is not to exceed 0.65 to 1.00. As of June 30, 2012, this covenant was met with a ratio of 0.41 to 1.00. The above ratio is calculated as the sum of DP&L’s current and long-term portion of debt, including its guarantee obligations, divided by the total of DP&L’s shareholder’s equity and total debt including guarantee obligations.
Credit Ratings
Standard & Poor’s recently put both DPL and DP&L on CreditWatch Negative reflecting the potential to lower the credit ratings of both entities in the near term pending greater clarity on the timing and transition to full market
rates for DP&L. They have also revised their assessment of DPL and DP&L’s business risk profiles to “strong” from “excellent” to reflect the increased competition in Ohio, the expected growth of the unregulated retail business and the increasing competitive pressure due to lower wholesale electric prices stressing profit margins.
If the rating agencies were to reduce our debt or credit ratings, our borrowing costs may increase, our potential pool of investors and funding resources may be reduced, and we may be required to post additional collateral under selected contracts. These events may have an adverse effect on our results of operations, financial condition and cash flows. In addition, any such reduction in our debt or credit ratings may adversely affect the trading price of our outstanding debt securities.
Off-Balance Sheet Arrangements
DPL – Guarantees
In the normal course of business, DPL enters into various agreements with its wholly owned subsidiaries, DPLE and DPLER, and its wholly owned subsidiary MC Squared, providing financial or performance assurance to third parties. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to these subsidiaries on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish these subsidiaries’ intended commercial purposes. During the six months ended June 30, 2012, DPL did not incur any losses related to the guarantees of these obligations and we believe it is unlikely that DPL would be required to perform or incur any losses in the future associated with any of the above guarantees.
At June 30, 2012, DPL had $26.4 million of guarantees to third parties, for future financial or performance assurance under such agreements, on behalf of DPLE, DPLER and MC Squared. The guarantee arrangements entered into by DPL with these third parties cover present and future obligations of DPLE, DPLER and MC Squared to such beneficiaries and are terminable at any time by DPL upon written notice to the beneficiaries. The carrying amount of obligations for commercial transactions covered by these guarantees and recorded in our Condensed Consolidated Balance Sheets was $1.0 million at June 30, 2012.
DP&L owns a 4.9% equity ownership interest in an electric generation company which is recorded using the cost method of accounting under GAAP. As of June 30, 2012, DP&L could be responsible for the repayment of 4.9%, or $69.2 million, of a $1,411.4 million debt obligation that features maturities ranging from 2013 to 2040. This would only happen if this electric generation company defaulted on its debt payments. As of June 30, 2012, we have no knowledge of such a default.
Commercial Commitments and Contractual Obligations
We enter into various contractual obligations and other commercial commitments that may affect the liquidity of our operations. At December 31, 2011, these included:
Payment Due | ||||||||||||||||||||
Total | Less than 1 Year | 1 – 3 Years | 3 – 5 Years | More Than 5 Years | ||||||||||||||||
($ in millions) | ||||||||||||||||||||
DPL: | ||||||||||||||||||||
Long-term debt | $ | 2,599.1 | $ | 0.4 | $ | 895.6 | $ | 450.2 | $ | 1,252.9 | ||||||||||
Interest payments | 1,171.2 | 138.6 | 243.9 | 203.5 | 585.2 | |||||||||||||||
Pension and postretirement payments | 261.1 | 25.6 | 50.8 | 52.1 | 132.6 | |||||||||||||||
Capital leases | 0.7 | 0.3 | 0.4 | — | — | |||||||||||||||
Operating leases | 1.5 | 0.5 | 0.8 | 0.2 | — | |||||||||||||||
Coal contracts(a) | 818.6 | 233.4 | 265.6 | 162.6 | 157.0 | |||||||||||||||
Limestone contracts(a) | 34.8 | 5.8 | 11.6 | 11.6 | 5.8 | |||||||||||||||
Purchase orders and other contractual obligations | 71.3 | 57.5 | 7.8 | 6.0 | — | |||||||||||||||
Total contractual obligations | $ | 4,958.3 | $ | 462.1 | $ | 1,476.5 | $ | 886.2 | $ | 2,133.5 |
Payment Due | ||||||||||||||||||||
DP&L: | Total | Less than 1 Year | 1 – 3 Years | 3 – 5 Years | More Than 5 Years | �� | ||||||||||||||
($ in millions) | ||||||||||||||||||||
Long-term debt | $ | 903.7 | $ | 0.4 | $ | 470.8 | $ | 0.2 | $ | 432.3 | ||||||||||
Interest payments | 404.3 | 39.9 | 49.9 | 31.8 | 282.7 | |||||||||||||||
Pension and postretirement payments | 261.1 | 25.6 | 50.8 | 52.1 | 132.6 | |||||||||||||||
Capital leases | 0.7 | 0.3 | 0.4 | — | — | |||||||||||||||
Operating leases | 1.5 | 0.5 | 0.8 | 0.2 | — | |||||||||||||||
Coal contracts(a) | 818.6 | 233.4 | 265.6 | 162.6 | 157.0 | |||||||||||||||
Limestone contracts(a) | 34.8 | 5.8 | 11.6 | 11.6 | 5.8 | |||||||||||||||
Purchase orders and other contractual obligations | 71.3 | 57.5 | 7.8 | 6.0 | — | |||||||||||||||
Total contractual obligations | $ | 2,496.0 | $ | 363.4 | $ | 857.7 | $ | 264.5 | $ | 1,010.4 |
(a) | Total at DP&L-operated units |
Long-term debt:
DPL’s Long-term debt as of June 30, 2012 consists of DPL’s unsecured notes and unsecured term loan, along with DP&L’s first mortgage bonds, tax-exempt pollution control bonds, capital leases, and the Wright-Patterson Air Force Base note. These long-term debt amounts include current maturities but exclude unamortized debt discounts and fair value adjustments.
DP&L’s Long-term debt as of June 30, 2012 consists of its first mortgage bonds, tax-exempt pollution control bonds, capital leases and the Wright-Patterson Air Force Base note. These long-term debt amounts include current maturities but exclude unamortized debt discounts.
See Note 7 of Notes to DPL’s Consolidated Financial Statements and Note 16 of Notes to DPL’s Condensed Consolidated Financial Statements.
Interest payments:
Interest payments are associated with the long-term debt described above. The interest payments relating to variable-rate debt are projected using the interest rate prevailing at December 31, 2011.
Pension and postretirement payments:
As of December 31, 2011, DPL, through its principal subsidiary DP&L, had estimated future benefit payments as outlined in Note 9 of Notes to DPL’s Consolidated Financial Statements. These estimated future benefit payments are projected through 2020.
Capital leases:
As of December 31, 2011, DPL, through its principal subsidiary DP&L, had two immaterial capital leases that expire in 2013 and 2014.
Operating leases:
As of December 31, 2011, DPL, through its principal subsidiary DP&L, had several immaterial operating leases with various terms and expiration dates.
Coal contracts:
DPL, through its principal subsidiary DP&L, has entered into various long-term coal contracts to supply the coal requirements for the generating plants it operates. Some contract prices are subject to periodic adjustment and have features that limit price escalation in any given year.
Limestone contracts:
DPL, through its principal subsidiary DP&L, has entered into various limestone contracts to supply limestone used in the operation of FGD equipment at its generating facilities.
Purchase orders and other contractual obligations:
As of December 31, 2011, DPL and DP&L had various other contractual obligations including non-cancelable contracts to purchase goods and services with various terms and expiration dates.
Reserve for uncertain tax positions:
Due to the uncertainty regarding the timing of future cash outflows associated with our unrecognized tax benefits of $25.0 million at December 31, 2011, we are unable to make a reliable estimate of the periods of cash settlement with the respective tax authorities and have not included such amounts in the contractual obligations table above.
There have been no material changes, outside the ordinary course of business, to our commercial commitments and to the information disclosed in the contractual obligations table above since December 31, 2011.
Market Risk
We are subject to certain market risks including, but not limited to, changes in commodity prices for electricity, coal, environmental emissions and gas, changes in capacity prices and fluctuations in interest rates. We use various market risk sensitive instruments, including derivative contracts, primarily to limit our exposure to fluctuations in commodity pricing. Our Commodity Risk Management Committee (CRMC), comprised of members of senior management, is responsible for establishing risk management policies and the monitoring and reporting of risk exposures relating to our DP&L-operated generation units. The CRMC meets on a regular basis with the objective of identifying, assessing and quantifying material risk issues and developing strategies to manage these risks.
Commodity Pricing Risk
Commodity pricing risk exposure includes the impacts of weather, market demand, increased competition and other economic conditions. To manage the volatility relating to these exposures at our DP&L-operated generation units, we use a variety of non-derivative and derivative instruments including forward contracts and futures contracts. These instruments are used principally for economic hedging purposes and none are held for trading purposes. Derivatives that fall within the scope of derivative accounting under GAAP must be recorded at their fair value and marked to market unless they qualify for cash flow hedge accounting. MTM gains and losses on derivative instruments that qualify for cash flow hedge accounting are deferred in AOCI until the forecasted transactions occur. We adjust the derivative instruments that do not qualify for cash flow hedging to fair value on a monthly basis and where applicable, we recognize a corresponding Regulatory asset for above-market costs or a Regulatory liability for below-market costs in accordance with regulatory accounting under GAAP.
The coal market has increasingly been influenced by both international and domestic supply and consumption, making the price of coal more volatile than in the past, and while we have substantially all of the total expected coal volume needed to meet our retail and firm wholesale sales requirements for 2012 under contract, sales requirements may change. The majority of the contracted coal is purchased at fixed prices. Some contracts provide for periodic adjustments. Fuel costs are affected by changes in volume and price and are driven by a number of variables including weather, the wholesale market price of power, certain provisions in coal contracts related to government imposed costs, counterparty performance and credit, scheduled outages and generation plant mix. To the extent we are not able to hedge against price volatility or recover increases through our fuel and purchased power recovery rider that began in January 2010, our results of operations, financial condition or cash flows could be materially affected.
For purposes of potential risk analysis, we use a sensitivity analysis to quantify potential impacts of market rate changes on the statements of results of operations. The sensitivity analysis represents hypothetical changes in market values that may or may not occur in the future.
In addition, the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), signed into law in July 2010, contains significant requirements relating to derivatives, including, among others, a requirement that certain transactions be cleared on exchanges that would necessitate the posting of cash collateral for these transactions. The Dodd-Frank Act provides a potential exception from these clearing and cash collateral requirements for commercial end-users. The Dodd-Frank Act requires the Commodity Futures Trading Commission to establish rules to implement the Dodd-Frank Act’s requirements and exceptions. Requirements to post collateral could reduce the cost effectiveness of entering into derivative transactions to reduce commodity price and interest rate volatility or could increase the demands on our liquidity or require us to increase our levels of debt to enter into such derivative transactions. Even if we were to qualify for an exception from these requirements, our counterparties that do not qualify for the exception may pass along any increased costs incurred by them through higher prices and reductions in unsecured credit limits or be unable to enter into certain transactions with us.
For purposes of potential risk analysis, we use a sensitivity analysis to quantify potential impacts of market rate changes on the statements of results of operations. The sensitivity analysis represents hypothetical changes in market values that may or may not occur in the future.
Commodity Derivatives
To minimize the risk of fluctuations in the market price of commodities, such as coal, power and heating oil, we may enter into commodity-forward and futures contracts to effectively hedge the cost/revenues of the commodity. Maturity dates of the contracts are scheduled to coincide with market purchases/sales of the commodity. Cash proceeds or payments between us and the counter-party at maturity of the contracts are recognized as an adjustment to the cost of the commodity purchased or sold. We generally do not enter into forward contracts beyond thirty-six months.
A 10% increase or decrease in the market price of our wholesale power forward contracts and heating oil forwards at December 31, 2011 would not have a significant effect on Net income.
The following table provides information regarding the volume and average market price of our NYMEX coal forward derivative contracts at December 31, 2011 and the effect to Net income if the market price were to increase or decrease by 10%:
NYMEX Coal Forwards | Contract Volume (in millions of Tons) | Weighted Average Market Price (per Ton) | Increase / Decrease in Net Income (in millions)(a) | |||||||||
2012-Purchase | 1.4 | $ | 70.37 | $ | 3.2 | |||||||
2013-Purchase | 0.2 | $ | 70.37 | $ | 0.7 | |||||||
2014-Purchase | 0.5 | $ | 74.11 | $ | 2.2 |
(a) | The Net Income effect of a 10% change in the market price of NYMEX Coal has been partially off-set by our partners' share of the gain or loss associated with the jointly-owned power plants and also by the retail customers' share of the gain or loss which is deferred on the balance sheet in conjunction with the fuel and purchased power recovery rider. |
A 10% increase or decrease in the market price of our heating oil forwards, NYMEX coal forwards and power forward contracts at June 30, 2012 would not have a significant effect on Net income.
Wholesale Revenues
Approximately 17% of DPL’s and 35% of DP&L’s electric revenues for the year ended December 31, 2011 were from sales of excess energy and capacity in the wholesale market (DP&L’s electric revenues in the wholesale market are reduced for sales to DPLER). Energy in excess of the needs of existing retail customers is sold in the wholesale market when we can identify opportunities with positive margins.
Approximately 18% of DPL’s and 30% of DP&L’s electric revenues for the year ended December 31, 2010 were from sales of excess energy and capacity in the wholesale market (DP&L’s electric revenues in the wholesale
market are reduced for sales to DPLER). Energy in excess of the needs of existing retail customers is sold in the wholesale market when we can identify opportunities with positive margins.
Approximately 17% of DPL’s and 20% of DP&L’s electric revenues for the year ended December 31, 2009 were from sales of excess energy and capacity in the wholesale market. Energy in excess of the needs of existing retail customers is sold in the wholesale market when we can identify opportunities with positive margins.
The table below provides the effect on annual Net income as of December 31, 2011, of a hypothetical increase or decrease of 10% in the price per megawatt hour of wholesale power (DP&L’s electric revenues in the wholesale market are reduced for sales to DPLER), including the impact of a corresponding 10% change in the portion of purchased power used as part of the sale (note the share of the internal generation used to meet the DPLER wholesale sale would not be affected by the 10% change in wholesale prices):
DPL | DP&L | |||||||
($ in millions) | ||||||||
Effect of 10% change in price per mWh | $ | 7.6 | $ | 6.6 |
Approximately 10% of DPL’s and 34% of DP&L’s electric revenues for the three months ended June 30, 2012 were from sales of excess energy and capacity in the wholesale market (DP&L’s electric revenues in the wholesale market are reduced for sales to DPLER). Energy in excess of the needs of existing retail customers is sold in the wholesale market when we can identify opportunities with positive margins.
Approximately 18% of DPL’s and 37% of DP&L’s electric revenues for the three months ended June 30, 2011 were from sales of excess energy and capacity in the wholesale market (DP&L’s electric revenues in the wholesale market are reduced for sales to DPLER). Energy in excess of the needs of existing retail customers is sold in the wholesale market when we can identify opportunities with positive margins.
Approximately 12% of DPL’s and 34% of DP&L’s electric revenues for the six months ended June 30, 2012 were from sales of excess energy and capacity in the wholesale market (DP&L’s electric revenues in the wholesale market are reduced for sales to DPLER). Energy in excess of the needs of existing retail customers is sold in the wholesale market when we can identify opportunities with positive margins.
Approximately 18% of DPL’s and 35% of DP&L’s electric revenues for the six months ended June 30, 2011 were from sales of excess energy and capacity in the wholesale market (DP&L’s electric revenues in the wholesale market are reduced for sales to DPLER). Energy in excess of the needs of existing retail customers is sold in the wholesale market when we can identify opportunities with positive margins.
The table below provides the effect on annual Net income as of June 30, 2012, of a hypothetical increase or decrease of 10% in the price per megawatt hour of wholesale power (DP&L’s electric revenues in the wholesale market are reduced for sales to DPLER), including the impact of a corresponding 10% change in the portion of purchased power used as part of the sale (note the share of the internal generation used to meet the DPLER wholesale sale would not be affected by the 10% change in wholesale prices):
DPL | DP&L | |||||||
($ in millions) | ||||||||
Effect of 10% change in price per mWh | $ | 6.0 | $ | 6.0 |
RPM Capacity Revenues and Costs
As a member of PJM, DP&L receives revenues from the RTO related to its transmission and generation assets and incurs costs associated with its load obligations for retail customers. PJM, which has a delivery year which runs from June 1 to May 31, has conducted auctions for capacity through the 2015/16 delivery year. The clearing prices for capacity during the PJM delivery periods from 2011/12 through 2015/16 are as follows:
PJM Delivery Year | ||||||||||||||||||||
2011/12 | 2012/13 | 2013/14 | 2014/15 | 2015/16 | ||||||||||||||||
Capacity clearing price ($/MW-day) | $ | 110 | $ | 16 | $ | 28 | $ | 126 | $ | 136 |
Our computed average capacity prices by calendar year are reflected in the table below:
Calendar Year | ||||||||||||||||||||
2011 | 2012 | 2013 | 2014 | 2015 | ||||||||||||||||
Computed average capacity price ($/MW-day) | $ | 137 | $ | 55 | $ | 23 | $ | 85 | $ | 132 |
Future RPM auction results are dependent on a number of factors, which include the overall supply and demand of generation and load, other state legislation or regulation, transmission congestion, and PJM’s RPM business rules. The volatility in the RPM capacity auction pricing has had and will continue to have a significant impact on DPL’s capacity revenues and costs. Although DP&L currently has an approved RPM rider in place to recover or repay any excess capacity costs or revenues, the RPM rider only applies to customers supplied under our SSO. Customer switching reduces the number of customers supplied under our SSO, causing more of the RPM capacity costs and revenues to be excluded from the RPM rider calculation.
The table below provides estimates of the effect on annual net income as of December 31, 2011 of a hypothetical increase or decrease of $10/MW-day in the RPM auction price. The table shows the impact resulting from capacity revenue changes. We did not include the impact of a change in the RPM capacity costs since these costs will either be recovered through the RPM rider for SSO retail customers or recovered through the development of our overall energy pricing for customers who do not fall under the SSO. These estimates include the impact of the RPM rider and are based on the levels of customer switching experienced through December 31, 2011. As of December 31, 2011, approximately 43% of DP&L’s RPM capacity revenues and costs were recoverable from SSO retail customers through the RPM rider.
DPL | DP&L | |||||||
($ in millions) | ||||||||
Effect of a $10/MW-day change in capacity auction pricing | $ | 5.2 | $ | 3.9 |
The table below provides estimates of the effect on annual net income as of June 30, 2012 of a hypothetical increase or decrease of $10/MW-day in the RPM auction price. The table shows the impact resulting from capacity revenue changes. We did not include the impact of a change in the RPM capacity costs since these costs will either be recovered through the RPM rider for SSO retail customers or recovered through the development of our overall energy pricing for customers who do not fall under the SSO. These estimates include the impact of the RPM rider and are based on the levels of customer switching experienced through June 30, 2012. As of June 30, 2012, approximately 48% of DP&L’s RPM capacity revenues and costs were recoverable from SSO retail customers through the RPM rider.
DPL | DP&L | |||||||
($ in millions) | ||||||||
Effect of a $10/MW-day change in capacity auction pricing | $ | 5.1 | $ | 3.8 |
Capacity revenues and costs are also impacted by, among other factors, the levels of customer switching, our generation capacity, the levels of wholesale revenues and our retail customer load. In determining the capacity price sensitivity above, we did not consider the impact that may arise from the variability of these other factors.
Fuel and Purchased Power Costs
DPL’s and DP&L’s fuel (including coal, gas, oil and emission allowances) and purchased power costs as a percentage of total operating costs in the years ended December 31, 2011 and 2010 were 37% and 43%, respectively. DPL’s and DP&L’s fuel (including coal, gas, oil and emission allowances) and purchased power costs as a percentage of total operating costs in the six months ended June 30, 2012 and 2011 were 34% and 36%, respectively. We have a significant portion of projected 2012 fuel needs under contract. The majority of our
contracted coal is purchased at fixed prices although some contracts provide for periodic pricing adjustments. We may purchase SO2 allowances for 2012; however, the exact consumption of SO2 allowances will depend on market prices for power, availability of our generation units and the actual sulfur content of the coal burned. We may purchase some NOx allowances for 2012 depending on NOx emissions. Fuel costs are affected by changes in volume and price and are driven by a number of variables including weather, reliability of coal deliveries, scheduled outages and generation plant mix.
Purchased power costs depend, in part, upon the timing and extent of planned and unplanned outages of our generating capacity. We will purchase power on a discretionary basis when wholesale market conditions provide opportunities to obtain power at a cost below our internal generation costs.
Effective January 1, 2010, DP&L was allowed to recover its SSO retail customers’ share of fuel and purchased power costs as part of the fuel rider approved by the PUCO. Since there has been an increase in customer switching, SSO customers represented approximately 43% and 48% of DP&L’s total fuel costs as of December 31, 2011 and June 30, 2012, respectively.. The table below provides the effect on annual net income as of December 31, 2011, of a hypothetical increase or decrease of 10% in the prices of fuel and purchased power, adjusted for the approximate 43% recovery:
DPL | DP&L | |||||||
($ in millions) | ||||||||
Effect of 10% change in fuel and purchased power | $ | 19.9 | $ | 18.2 |
The table below provides the effect on annual net income as of June 30, 2012, of a hypothetical increase or decrease of 10% in the prices of fuel and purchased power, adjusted for the approximate 48% recovery:
DPL | DP&L | |||||||
($ in millions) | ||||||||
Effect of 10% change in fuel and purchased power | $ | 17.0 | $ | 15.3 |
Interest Rate Risk
As a result of our normal investing and borrowing activities, our financial results are exposed to fluctuations in interest rates which we manage through our regular financing activities. We maintain both cash on deposit and investments in cash equivalents that may be affected by adverse interest rate fluctuations. DPL and DP&L have both fixed-rate and variable-rate long-term debt. DPL’s variable-rate debt consists of a $425.0 million unsecured term loan with a syndicated bank group. The term loan interest rate fluctuates with changes in an underlying interest rate index, typically LIBOR. DP&L’s variable-rate debt is comprised of publicly held pollution control bonds. The variable-rate bonds bear interest based on a prevailing rate that is reset weekly based on a comparable market index. Market indexes can be affected by market demand, supply, market interest rates and other economic conditions. See Note 7 and Note 18 of Notes to DPL’s Consolidated Financial Statements. Also see Note 6 of Notes to DPL’s Condensed Consolidated Financial Statements.
We partially hedge against interest rate fluctuations by entering into interest rate swap agreements to limit the interest rate exposure on the underlying financing. As of June 30, 2012, we have entered into interest rate hedging relationships with an aggregate notional amount of $160.0 million related to planned future borrowing activities in calendar year 2013. The average interest rate associated with the $160.0 million aggregate notional amount interest rate hedging relationships is 3.8%. We are limiting our exposure to changes in interest rates since we believe the market interest rates at which we will be able to borrow in the future may increase. Any additional credit rating downgrades could affect our liquidity and further increase our cost of capital.
The carrying value of DPL’s debt was $2,619.6 million at June 30, 2012, consisting of DPL’s unsecured notes and unsecured term loan, along with DP&L’s first mortgage bonds, tax-exempt pollution control bonds, capital leases, and the Wright-Patterson Air Force Base note. All of DPL’s debt was adjusted to fair value at the Merger date according to FASC 805. The fair value of this debt at June 30, 2012 was $2,744.4 million, based on current market prices or discounted cash flows using current rates for similar issues with similar terms and remaining
maturities. The following table provides information about DPL’s debt obligations that are sensitive to interest rate changes:
Carrying Value and Interest Rate Detail by Contractual Maturity Date
DPL
Twelve Months Ending June 30, | ||||||||||||||||||||||||||||||||
2013 | 2014 | 2015 | 2016 | 2017 | Thereafter | Carrying value at June 30, 2012(a) | Fair value at June 30, 2012(a) | |||||||||||||||||||||||||
($ in millions) | ||||||||||||||||||||||||||||||||
Long-term debt | ||||||||||||||||||||||||||||||||
Variable-rate debt | $ | — | $ | — | $ | 425.0 | $ | — | $ | — | $ | 100.0 | $ | 525.0 | $ | 525.0 | ||||||||||||||||
Average interest rate | 0.0 | % | 0.0 | % | 2.2 | % | 0.0 | % | 0.0 | % | 0.2 | % | ||||||||||||||||||||
Fixed-rate debt | $ | 0.4 | $ | 494.4 | $ | 0.1 | $ | 0.1 | $ | 450.1 | $ | 1,149.5 | $ | 2,094.6 | $ | 2,219.4 | ||||||||||||||||
Average interest rate | 4.8 | % | 5.1 | % | 4.2 | % | 4.2 | % | 6.5 | % | 6.6 | % | ||||||||||||||||||||
Total | $ | 2,619.6 | $ | 2,744.4 |
(a) | Fixed rate debt totals include unamortized debt discounts. |
The carrying value of DP&L’s debt was $903.2 million at June 30, 2012, consisting of its first mortgage bonds, tax-exempt pollution control bonds, capital leases and the Wright-Patterson Air Force Base note. The fair value of this debt was $938.9 million, based on current market prices or discounted cash flows using current rates for similar issues with similar terms and remaining maturities. The following table provides information about DP&L’s debt obligations that are sensitive to interest rate changes. Note that the DP&L debt was not revalued using push-down accounting as a result of the Merger.
DP&L
Twelve Months Ending June 30, | ||||||||||||||||||||||||||||||||
2013 | 2014 | 2015 | 2016 | 2017 | Thereafter | Carrying value at June 30, 2012(a) | Fair value at June 30, 2012(a) | |||||||||||||||||||||||||
($ in millions) | ||||||||||||||||||||||||||||||||
Long-term debt | ||||||||||||||||||||||||||||||||
Variable-rate debt | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 100.0 | $ | 100.0 | $ | 100.0 | ||||||||||||||||
Average interest rate | 0.0 | % | 0.0 | % | 0.0 | % | 0.0 | % | 0.0 | % | 0.2 | % | ||||||||||||||||||||
Fixed-rate debt | $ | 0.4 | $ | 470.4 | $ | 0.1 | $ | 0.1 | $ | 0.1 | $ | 332.1 | $ | 803.2 | $ | 838.9 | ||||||||||||||||
Average interest rate | 4.8 | % | 5.1 | % | 4.2 | % | 4.2 | % | 4.2 | % | 4.8 | % | ||||||||||||||||||||
Total | $ | 903.2 | $ | 938.9 |
(a) | Fixed rate debt totals include unamortized debt discounts. |
Debt maturities occurring in 2012 are discussed under “—Financial Condition, Liquidity and Capital Requirements.”
Long-term Debt Interest Rate Risk Sensitivity Analysis
Our estimate of market risk exposure is presented for our fixed-rate and variable-rate debt at December 31, 2011 and June 30, 2012, for which an immediate adverse market movement causes a potential material impact on our financial condition, results of operations, or the fair value of the debt. We believe that the adverse market movement represents the hypothetical loss to future earnings and does not represent the maximum possible loss nor any expected actual loss, even under adverse conditions, because actual adverse fluctuations would likely differ. As of December 31, 2011 and June 30, 2012, we did not hold any market risk sensitive instruments which were entered into for trading purposes.
DPL | Carrying value at December 31, 2011 | Fair value at December 31, 2011 | One Percent Interest Rate Risk | |||||||||
($ in millions) | ||||||||||||
Long-term debt | ||||||||||||
Variable-rate debt | $ | 525.0 | $ | 525.0 | $ | 5.3 | ||||||
Fixed-rate debt | 2,104.3 | 2,185.6 | 21.9 | |||||||||
Total | $ | 2,629.3 | $ | 2,710.6 | $ | 27.2 | ||||||
DP&L | Carrying value at December 31, 2011 | Fair value at December 31, 2011 | One Percent Interest Rate Risk | |||||||||
($ in millions) | ||||||||||||
Long-term debt | ||||||||||||
Variable-rate debt | $ | 100.0 | $ | 100.0 | $ | 1.0 | ||||||
Fixed-rate debt | 803.4 | 834.5 | 8.4 | |||||||||
Total | $ | 903.4 | $ | 934.5 | $ | 9.4 |
DPL | Carrying value at June 30, 2012 | Fair value at June 30, 2012 | One percent interest rate risk | |||||||||
($ in millions) | ||||||||||||
Long-term debt | ||||||||||||
Variable-rate debt | $ | 525.0 | $ | 525.0 | $ | 5.3 | ||||||
Fixed-rate debt | 2,094.6 | 2,219.4 | 22.2 | |||||||||
Total | $ | 2,619.6 | $ | 2,744.4 | $ | 27.5 |
DP&L | Carrying value at June 30, 2012 | Fair value at June 30, 2012 | One percent interest rate risk | |||||||||
($ in millions) | ||||||||||||
Long-term debt | ||||||||||||
Variable-rate debt | $ | 100.0 | $ | 100.0 | $ | 1.0 | ||||||
Fixed-rate debt | 803.2 | 838.9 | 8.4 | |||||||||
Total | $ | 903.2 | $ | 938.9 | $ | 9.4 |
DPL’s debt is comprised of both fixed-rate debt and variable-rate debt. In regard to fixed rate debt, the interest rate risk with respect to DPL’s long-term debt primarily relates to the potential impact a decrease of one percentage point in interest rates has on the fair value of DPL’s $2,094.6 million of fixed-rate debt and not on DPL’s financial condition or results of operations. On the variable-rate debt, the interest rate risk with respect to DPL’s long-term debt represents the potential impact an increase of one percentage point in the interest rate has on DPL’s results of operations related to DPL’s $525.0 million variable-rate long-term debt outstanding as of June 30, 2012.
DP&L’s interest rate risk with respect to DP&L’s long-term debt primarily relates to the potential impact a decrease in interest rates of one percentage point has on the fair value of DP&L’s $803.2 million of fixed-rate debt and not on DP&L’s financial condition or DP&L’s results of operations. On the variable-rate debt, the interest rate risk with respect to DP&L’s long-term debt represents the potential impact an increase of one percentage point in the interest rate has on DP&L’s results of operations related to DP&L’s $100.0 million variable-rate long-term debt outstanding as of June 30, 2012.
Equity Price Risk
As of June 30, 2012, approximately 26% of the defined benefit pension plan assets were comprised of investments in equity securities and 74% related to investments in fixed income securities, cash and cash equivalents, and alternative investments. We use an investment adviser to assist in managing our investment portfolio. The market value of the equity securities was approximately $91.1 million at June 30, 2012. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $9.1 million reduction in fair value as of June 30, 2012.
Credit Risk
Credit risk is the risk of an obligor's failure to meet the terms of any investment contract, loan agreement or otherwise perform as agreed. Credit risk arises from all activities in which success depends on issuer, borrower or counterparty performance, whether reflected on or off the balance sheet. We limit our credit risk by assessing the creditworthiness of potential counterparties before entering into transactions with them and continue to evaluate their creditworthiness after transactions have been originated. We use the three leading corporate credit rating agencies and other current market-based qualitative and quantitative data to assess the financial strength of counterparties on an ongoing basis. We may require various forms of credit assurance from counterparties in order to mitigate credit risk.
Critical Accounting Estimates
DPL’s Consolidated Financial Statements and DP&L’s Financial Statements are prepared in accordance with U.S. GAAP. In connection with the preparation of these financial statements, our management is required to make assumptions, estimates and judgments that affect the reported amounts of assets, liabilities, revenues, expenses and the related disclosure of contingent liabilities. These assumptions, estimates and judgments are based on our historical experience and assumptions that we believe to be reasonable at the time. However, because future events and their effects cannot be determined with certainty, the determination of estimates requires the exercise of judgment. Our critical accounting estimates are those which require assumptions to be made about matters that are highly uncertain.
Different estimates could have a material effect on our financial results. Judgments and uncertainties affecting the application of these policies and estimates may result in materially different amounts being reported under different conditions or circumstances. Historically, however, recorded estimates have not differed materially from actual results. Significant items subject to such judgments include: the carrying value of property, plant and equipment; unbilled revenues; the valuation of derivative instruments; the valuation of insurance and claims liabilities; the valuation of allowances for receivables and deferred income taxes; regulatory assets and liabilities; reserves recorded for income tax exposures; litigation; contingencies; the valuation of AROs; and assets and liabilities related to employee benefits.
Impairments and Assets Held for Sale: In accordance with the provisions of GAAP relating to the accounting for goodwill, goodwill is not amortized, but is evaluated for impairment at least annually or more frequently if impairment indicators are present. In evaluating the potential impairment of goodwill, we make estimates and assumptions about revenue, operating cash flows, capital expenditures, growth rates and discount rates based on our budgets and long term forecasts, macroeconomic projections, and current market expectations of returns on similar assets. There are inherent uncertainties related to these factors and management’s judgment in applying these factors. Generally, the fair value of a reporting unit is determined using a discounted cash flow valuation model. We could be required to evaluate the potential impairment of goodwill outside of the required annual assessment process if we experience situations, including but not limited to: deterioration in general economic conditions, operating or regulatory environment; increased competitive environment; increase in fuel costs particularly when we are unable to pass its effect to customers; negative or declining cash flows; loss of a key contract or customer particularly when we are unable to replace it on equally favorable terms; or adverse actions or assessments by a regulator. These types of events and the resulting analyses could result in goodwill impairment expense, which could substantially affect our results of operations for those periods.
In accordance with the provisions of GAAP relating to the accounting for impairments, long-lived assets to be held and used are reviewed for impairment whenever events or circumstances indicate that the carrying amount may not be recoverable. When required, impairment losses on assets to be held and used are recognized based on the fair value of the asset. We determine the fair value of these assets based upon estimates of future cash flows, market value of similar assets, if available or independent appraisals, if required. In analyzing the fair value and recoverability using future cash flows, we make projections based on a number of assumptions and estimates of growth rates, future economic conditions, assignment of discount rates and estimates of terminal values. An impairment loss is recognized if the carrying amount of the long-lived asset is not recoverable from its undiscounted cash flows. The measurement of impairment loss is the difference between the carrying amount and fair value of the asset.
Revenue Recognition (including Unbilled Revenue): We consider revenue realized, or realizable, and earned when persuasive evidence of an arrangement exists, the products or services have been provided to the customer, the sales price is fixed or determinable, and collection is reasonably assured. The determination of the energy sales to customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. We recognize revenues using an accrual method for retail and other energy sales that have not yet been billed, but where electricity has been consumed. This is termed “unbilled revenues” and is a widely recognized and accepted practice for utilities. At the end of each month, unbilled revenues are determined by the estimation of unbilled energy provided to customers since the date of the last meter reading, projected line losses, the assignment of unbilled energy provided to customer classes and the average rate per customer class. Given our estimation method and the fact that customers are billed monthly, we believe it is unlikely that materially different results will occur in future periods when these amounts are subsequently billed.
Income Taxes: Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. The interpretation of tax laws involves uncertainty, since taxing authorities may interpret them differently. Ultimate resolution of income tax matters may result in favorable or unfavorable impacts to Net income and cash flows and adjustments to tax-related assets and liabilities could be material. We have adopted the provisions of GAAP relating to the accounting for uncertainty in income taxes. Taking into consideration the uncertainty and judgment involved in the determination and filing of income taxes, these GAAP provisions establish standards for recognition and measurement in financial statements of positions taken, or expected to be taken, by an entity on its income tax returns. Positions taken by an entity on its income tax returns that are recognized in the financial statements must satisfy a more-likely-than-not recognition threshold, assuming that the position will be examined by taxing authorities with full knowledge of all relevant information.
Deferred income tax assets and liabilities represent future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. We evaluate quarterly the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. Failure to achieve forecasted taxable income or successfully implement tax planning strategies may affect the realization of deferred tax assets.
Regulatory Assets and Liabilities: Application of the provisions of GAAP relating to regulatory accounting requires us to reflect the effect of rate regulation in DPL’s Consolidated Financial Statements and DP&L’s Financial Statements. For regulated businesses subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, we defer these costs as Regulatory assets that otherwise would be expensed by nonregulated companies. Likewise, we recognize Regulatory liabilities when it is probable that regulators will require customer refunds through future rates and when revenue is collected from customers for expenses that are not yet incurred. Regulatory assets are amortized into expense and Regulatory liabilities are amortized into income over the recovery period authorized by the regulator.
We evaluate our Regulatory assets to determine whether or not they are probable of recovery through future rates and make various assumptions in our analyses. The expectations of future recovery are generally based on orders issued by regulatory commissions or historical experience, as well as discussions with applicable regulatory authorities. If recovery of a regulatory asset is determined to be less than probable, it will be written off in the
period the assessment is made. We currently believe the recovery of our Regulatory assets is probable. See Note 4 of Notes to DPL’s Consolidated Financial Statements.
AROs: In accordance with the provisions of GAAP relating to the accounting for AROs, legal obligations associated with the retirement of long-lived assets are required to be recognized at their fair value at the time those obligations are incurred. Upon initial recognition of a legal liability, costs are capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. These GAAP provisions also require that components of previously recorded depreciation related to the cost of removal of assets upon future retirement, whether legal AROs or not, must be removed from a company’s accumulated depreciation reserve and be reclassified as a regulatory liability. We make assumptions, estimates and judgments that affect the reported amounts of assets, liabilities and expenses as they relate to AROs. These assumptions and estimates are based on historical experience and assumptions that we believe to be reasonable at the time.
Insurance and Claims Costs: In addition to insurance obtained from third-party providers, MVIC, a wholly-owned captive subsidiary of DPL, provides insurance coverage solely to us, our subsidiaries and, in some cases, our partners in commonly-owned facilities we operate, for workers’ compensation, general liability, property damage, and directors’ and officers’ liability. Insurance and Claims Costs on DPL’s Consolidated Balance Sheets of DPL include estimated liabilities for insurance and claims costs of approximately $14.2 million and $10.1 million for 2011 and 2010, respectively. Furthermore, DP&L is responsible for claim costs below certain coverage thresholds of MVIC for the insurance coverage noted above. In addition, DP&L has estimated liabilities for medical, life and disability claims costs below certain coverage thresholds of third-party providers. DPL and DP&L record these additional insurance and claims costs of approximately $18.9 million and $19.0 million for 2011 and 2010, respectively, within Other current liabilities and Other deferred credits on the balance sheets. The estimated liabilities for MVIC at DPL and the estimated liabilities for workers’ compensation, medical, life and disability claims at DP&L are actuarially determined based on a reasonable estimation of insured events occurring. There is uncertainty associated with the loss estimates and actual results may differ from the estimates. Modification of these loss estimates based on experience and changed circumstances is reflected in the period in which the estimate is re-evaluated.
Pension and Postretirement Benefits: We account for and disclose pension and postretirement benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postretirement plans. These GAAP provisions require the use of assumptions, such as the discount rate for liabilities and long-term rate of return on assets, in determining the obligations, annual cost, and funding requirements of the plans.
For the Successor period in 2011 and continuing for 2012, we have decreased our long-term rate of return assumption from 8.00% to 7.00% for pension plan assets. We are maintaining our long-term rate of return assumption of 6.00% for other postemployment benefit plan assets. These rates of return represent our long-term assumptions based on our current portfolio mixes. Also, for the Successor period and for 2012, we have decreased our assumed discount rate to 4.88% from 5.31% for pension and to 4.14% from 4.96% for postretirement benefits expense to reflect current duration-based yield curve discount rates. A one percent change in the rate of return assumption for pension would result in an increase or decrease to the 2012 pension expense of approximately $3.4 million. A one percent change in the discount rate for pension would result in an increase or decrease to the 2012 pension expense of approximately $1.2 million.
In future periods, differences in the actual return on pension and other post-employment benefit plan assets and assumed return, or changes in the discount rate, will affect the timing of contributions to the plans, if any. We provide postretirement health care benefits to employees who retired prior to 1987. A one percentage point change in the assumed health care cost trend rate would affect postretirement benefit costs by less than $1.0 million.
Contingent and Other Obligations: During the conduct of our business, we are subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject us to environmental, litigation, insurance and other risks. We periodically evaluate our exposure to such risks and record estimated liabilities for those matters where a loss is considered probable and reasonably estimable in accordance with GAAP. In recording such estimated liabilities, we may make assumptions, estimates and judgments that affect the reported amounts of assets, liabilities and expenses as they relate to contingent and other obligations. These assumptions and
estimates are based on historical experience and assumptions and may be subject to change. We, however, believe such estimates and assumptions are reasonable.
Legal and Other Matters
In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We are also from time to time involved in other reviews, investigations and proceedings by governmental and regulatory agencies regarding our business, certain of which may result in adverse judgments, settlements, fines, penalties, injunctions or other relief. We believe the amounts provided in our Financial Statements, as prescribed by GAAP, for these matters are adequate in light of the probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims and other matters (including those matters noted below) and to comply with applicable laws and regulations will not exceed the amounts reflected in our Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided for in our Financial Statements, cannot be reasonably determined.
A discussion of Legal and Other Matters is described in Note 18 of the DPL Inc. Notes to Consolidated Financial Statements and Note 13 of the DPL Inc. Notes to Condensed Consolidated Financial Statements. A discussion of environmental matters and competition and regulatory matters affecting both DPL and DP&L is described in “Business – Environmental Considerations” and “Business – Competition and Regulation.” Such discussions are incorporated by reference in this Management’s Discussion and Analysis of Results of Operations and Financial Condition and made a part hereof.
Recently Issued Accounting Pronouncements
A discussion of recently issued accounting pronouncements is described in Note 1 of Notes to DPL’s Consolidated Financial Statements and Condensed Consolidated Financial Statements and such discussion is incorporated by reference in this Management’s Discussion and Analysis of Results of Operations and Financial Condition and made a part hereof.
Organization
DPL is a regional energy company organized in 1985 under the laws of Ohio. DPL’s two reportable segments are the Utility segment, comprised of its DP&L subsidiary, and the Competitive Retail segment, comprised of its DPLER subsidiary. Refer to Note 14 of Notes to DPL’s Condensed Consolidated Financial Statements for more information relating to these reportable segments.
DPL was acquired by The AES Corporation on November 28, 2011 and is a wholly-owned, indirect subsidiary of AES. See Note 2 of Notes to DPL’s Condensed Consolidated Financial Statements.
DP&L is a public utility incorporated in 1911 under the laws of Ohio. DP&L sells electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio. Electricity for DP&L’s 24 county service area is primarily generated at eight coal-fired power plants and is distributed to more than 500,000 retail customers. Principal industries served include automotive, food processing, paper, plastic, manufacturing and defense. DP&L’s sales reflect the general economic conditions and seasonal weather patterns of the area. DP&L sells any excess energy and capacity into the wholesale market. DP&L also sells electricity to DPLER, an affiliate, to satisfy the electric requirements of its retail customers.
DPLER sells competitive retail electric service, under contract, to residential, commercial, industrial and governmental customers. DPLER’s operations include those of its wholly-owned subsidiary, MC Squared Energy Services, LLC, which was purchased on February 28, 2011. DPLER has approximately 70,000 customers currently located throughout Ohio and Illinois. DPLER does not own any transmission or generation assets, and all of DPLER’s electric energy was purchased from DP&L or PJM to meet its sales obligations. DPLER’s sales reflect the general economic conditions and seasonal weather patterns of the areas it serves.
DPL’s other significant subsidiaries include: DPLE, which owns and operates peaking generating facilities from which it makes wholesale sales of electricity and MVIC, DPL’s captive insurance company that provides insurance services to us and DPL’s other subsidiaries.
All of DPL’s subsidiaries are wholly-owned. DP&L does not have any subsidiaries.
DPL also has a wholly owned business trust, DPL Capital Trust II, formed for the purpose of issuing trust capital securities to investors.
DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators while its generation business is deemed competitive under Ohio law. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are expected to be recovered in future customer rates and regulatory liabilities when current recoveries in customer rates relate to expected future costs.
DPL and its subsidiaries employed 1,493 people as of June 30, 2012, of which 1,446 employees were employed by DP&L. Approximately 53% of all employees are under a collective bargaining agreement which expires on October 31, 2014.
Electric Operations and Fuel Supply
2011 Summer Generating Capacity | ||||||||||||
Coal Fired | Solar, Combustion Turbines and Peaking Units | Total | ||||||||||
(Amounts in MWs) | ||||||||||||
DPL | 2,830 | 988 | 3,818 | |||||||||
DP&L | 2,830 | 432 | 3,262 |
DPL’s 2011 summer generating capacity, including peaking units, was approximately 3,818 MW. Of this capacity, approximately 2,830 MW, or 74%, is derived from coal-fired steam generating stations and the balance of approximately 988 MW, or 26%, consists of solar, combustion turbine and diesel peaking units.
DP&L’s 2011 summer generating capacity, including peaking units, is approximately 3,262 MW. Of this capacity, approximately 2,830 MW, or 87%, was derived from coal-fired steam generating stations and the balance of approximately 432 MW, or 13%, consists of solar, combustion turbine and diesel peaking units.
Our all-time net peak load was 3,270 MW, occurring August 8, 2007.
Approximately 87% of the existing steam generating capacity is provided by certain generating units owned as tenants in common with Duke Energy and CSP. As tenants in common, each company owns a specified share of each of these units, is entitled to its share of capacity and energy output and has a capital and operating cost responsibility proportionate to its ownership share. DP&L’s remaining steam generating capacity (approximately 365 MW) is derived from a generating station owned solely by DP&L. Additionally, DP&L, Duke Energy and CSP own, as tenants in common, 880 circuit miles of 345,000-volt transmission lines. DP&L has several interconnections with other companies for the purchase, sale and interchange of electricity.
In 2011, we generated 98.3% of our electric output from coal-fired units and 1.7% from solar, oil and natural gas-fired units.
The following table sets forth DP&L’s and DPLE’s generating stations as of December 31, 2011 and, where indicated, those stations which DP&L owns as tenants in common.
Approximate Summer MW Rating | ||||||||||
Station | Ownership* | Operating Company | Location | DP&L Portion | Total | |||||
Coal Units | ||||||||||
Hutchings | W | DP&L | Miamisburg,OH | 365 | 365 | |||||
Killen | C | DP&L | Wrightsville,OH | 402 | 600 | |||||
Stuart | C | DP&L | Aberdeen,OH | 808 | 2,308 | |||||
Conesville-Unit 4 | C | CSP | Conesville,OH | 129 | 780 | |||||
Beckjord-Unit 6 | C | Duke Energy | New Richmond,OH | 207 | 414 | |||||
Miami Fort-Units 7 & 8 | C | Duke Energy | North Bend,OH | 368 | 1,020 | |||||
East Bend-Unit 2 | C | Duke Energy | Rabbit Hash, KY | 186 | 600 | |||||
Zimmer | C | Duke Energy | Moscow,OH | 365 | 1,300 | |||||
Solar, Combustion Turbines or Diesel | ||||||||||
Hutchings | W | DP&L | Miamisburg,OH | 25 | 25 | |||||
Yankee Street | W | DP&L | Centerville,OH | 101 | 101 | |||||
Yankee Solar | W | DP&L | Centerville,OH | 1 | 1 | |||||
Monument | W | DP&L | Dayton,OH | 12 | 12 | |||||
Tait Diesels | W | DP&L | Dayton,OH | 10 | 10 | |||||
Sidney | W | DP&L | Sidney,OH | 12 | 12 | |||||
Tait Units 1-3 | W | DP&L | Moraine, OH | 256 | 256 | |||||
Killen | C | DP&L | Wrightsville,OH | 12 | 18 | |||||
Stuart | C | DP&L | Aberdeen,OH | 3 | 10 | |||||
Montpelier Units 1-4 | W | DPLE | Poneto,IN | 236 | 236 | |||||
Tait Units 4-7 | W | DPLE | Moraine, OH | 320 | 320 | |||||
Total approximate summer generating capacity | 3,818 | 8,388 |
*W = Wholly-Owned
C = Commonly-Owned
In addition to the above, DP&L also owns a 4.9% equity ownership interest in OVEC, an electric generating company. OVEC has two plants located in Cheshire, Ohio and Madison, Indiana with a combined generation capacity of approximately 2,265 MW. DP&L’s share of this generation capacity is approximately 111 MW.
We have substantially all of the total expected coal volume needed to meet our retail and firm wholesale sales requirements for 2012 under contract. The majority of the contracted coal is purchased at fixed prices. Some contracts provide for periodic adjustments and some are priced based on market indices. Fuel costs are affected by changes in volume and price and are driven by a number of variables including weather, the wholesale market price of power, certain provisions in coal contracts related to government imposed costs, counterparty performance and credit, scheduled outages and generation plant mix. Due to the installation of emission controls equipment at certain commonly owned units and barring any changes in the regulatory environment in which we operate, we expect to have a balanced SO2 and NOx position for 2012.
The gross average cost of fuel consumed per kWh was as follows:
Average Cost of Fuel Consumed (¢/kWh) | ||||||||||||
2011 | 2010 | 2009 | ||||||||||
DPL | 2.76 | 2.42 | 2.39 | |||||||||
DP&L | 2.71 | 2.37 | 2.36 |
For further information about our business, also see “Management’s Discussion and Analysis of Results of Operations and Financial Condition—Business Overview.”
Seasonality
The power generation and delivery business is seasonal and weather patterns have a material effect on operating performance. In the region we serve, demand for electricity is generally greater in the summer months associated with cooling and in the winter months associated with heating as compared to other times of the year. Unusually mild summers and winters could have an adverse effect on our results of operations, financial condition and cash flows.
Rate Regulation and Government Legislation
DP&L’s sales to SSO retail customers are subject to rate regulation by the PUCO. DP&L’s transmission rates and wholesale electric rates to municipal corporations, rural electric co-operatives and other distributors of electric energy are subject to regulation by the FERC under the Federal Power Act.
Ohio law establishes the process for determining SSO retail rates charged by public utilities. Regulation of retail rates encompasses the timing of applications, the effective date of rate increases, the recoverable cost basis upon which the rates are set and other related matters. Ohio law also established the Office of the OCC, which has the authority to represent residential consumers in state and federal judicial and administrative rate proceedings.
Ohio legislation extends the jurisdiction of the PUCO to the records and accounts of certain public utility holding company systems, including DPL. The legislation extends the PUCO’s supervisory powers to a holding company system’s general condition and capitalization, among other matters, to the extent that such matters relate to the costs associated with the provision of public utility service. Based on existing PUCO and FERC authorization,
regulatory assets and liabilities are recorded on the balance sheets. See Note 4 of Notes to DPL’s Consolidated Financial Statements and Condensed Consolidated Financial Statements.
Competition and Regulation
Ohio Matters
Ohio Retail Rates
The PUCO maintains jurisdiction over DP&L’s delivery of electricity, SSO and other retail electric services.
On May 1, 2008, substitute SB 221, an Ohio electric energy bill, was signed by the Governor and went into effect July 31, 2008. This law required that all Ohio distribution utilities file either an ESP or MRO to establish rates for SSO service. Under the MRO, a periodic competitive bid process will set the retail generation price after the utility demonstrates that it can meet certain market criteria and bid requirements. Also, under this option, utilities that still own generation in the state are required to phase-in the MRO over a period of not less than five years. An ESP may allow for cost-based adjustments to the SSO for costs associated with environmental compliance; fuel and purchased power; construction of new or investment in specified generating facilities; and the provision of standby and default service, operating, maintenance, or other costs including taxes. As part of its ESP, a utility is permitted to file an infrastructure improvement plan that will specify the initiatives the utility will take to rebuild, upgrade, or replace its electric distribution system, including cost recovery mechanisms. Both the MRO and ESP option involve a “significantly excessive earnings test” based on the earnings of comparable companies with similar business and financial risks. On March 30, 2012, DP&L filed with the PUCO for approval of its next SSO to replace the existing ESP that expires on December 31, 2012. The initial filing indicated that the proposed MRO rates, if approved by the PUCO, would reduce DP&L’s revenues by about $30 million in the first year after they are applied, based on the level of SSO sales contained in the filing. The filing requested approval of the five-year and five month MRO, which will be effective January 1, 2013, and would phase in market rates over this period. The PUCO is currently reviewing the filing and no decision has been made. The outcome of the proceeding is uncertain and could have a material impact on our results.
SB 221 and the implementation rules contain targets relating to advanced energy portfolio standards, renewable energy, demand reduction and energy efficiency standards. If any targets are not met, compliance penalties will apply unless the PUCO makes certain findings that would excuse performance. DP&L is currently meeting its renewable requirements and expects to remain in compliance. The PUCO found that both DP&L and DPLER met the renewable targets in 2009, and the PUCO Staff recommended that the Commission find that they both met the renewable targets for 2010.
On May 19, 2010 the Commission approved in part and denied in part DP&L’s request that the PUCO find that it met the 2009 energy efficiency portfolio requirements and directed DP&L to file a measurement and verification plan as well as a market potential study. We made this filing and settled the case through a stipulation that was approved in April 2011. The next energy efficiency portfolio plan is due to be filed in April 2013.
We are unable to predict how the PUCO will respond to many of the filings discussed above, but believe that the outcome for the non-ESP/MRO filings will not be material to our financial condition or results of operations. However, as the energy efficiency and alternative energy targets get increasingly larger over time, the costs of complying with SB 221 and the PUCO’s implementing rules or the results of our ESP/MRO filing on March 30, 2012 could have a material effect on our financial condition or results of operations.
The ESP Stipulation also provided for the establishment of a fuel and purchased power recovery rider beginning January 1, 2010. The fuel rider fluctuates based on actual costs and recoveries and is modified at the start of each seasonal quarter: March 1, June 1, September 1 and December 1 each year. As part of the PUCO approval process, an outside auditor was hired in 2011 to review fuel costs and the fuel procurement process for 2010. DP&L and all of the active participants in this proceeding reached a Stipulation and Recommendation which was approved by the PUCO on November 9, 2011. In November 2011, DP&L recorded a $25 million pretax ($16 million net of tax) adjustment as a result of the approval of the fuel settlement agreement by the PUCO. The adjustment was due to the
reversal of a provision recorded in accordance with the regulatory accounting rules. An audit of 2011 fuel costs is currently ongoing. The outcome of that audit is uncertain.
As a member of PJM, DP&L receives revenues from the RTO related to its transmission and generation assets and incurs costs associated with its load obligations for retail customers. SB 221 included a provision that would allow Ohio electric utilities to seek and obtain a reconcilable rider to recover RTO-related costs and credits. DP&L’s TCRR and PJM RPM riders were initially approved in November 2009 to recover these costs. Both the TCRR and the RPM riders assign costs and revenues from PJM monthly bills to retail ratepayers based on the percentage of SSO retail customers’ load and sales volumes to total retail load and total retail and wholesale volumes. Customer switching to CRES providers decreases DP&L’s SSO retail customers’ load and sales volumes. Therefore, increases in customer switching cause more of the RPM capacity costs and revenues to be excluded from the RPM rider calculation. RPM capacity costs and revenues are discussed further under “Risk Factors – Our membership in a regional transmission organization presents risks that could have a material adverse effect on our results of operations, financial condition and cash flows.” DP&L’s annual true-up of these two riders was approved by the PUCO by an order dated April 27, 2011 and its 2012 filing is still pending.
On September 9, 2009, the PUCO issued an order establishing a significantly excessive earnings test (SEET) proceeding pursuant to provisions contained in SB 221. The PUCO issued an order on June 30, 2010 to establish general rules for calculating the earnings and comparing them to a comparable group to determine whether there were significantly excessive earnings. The other three Ohio utilities were required to make their SEET determinations in 2011 and 2010. Pursuant to the ESP Stipulation, DP&L becomes subject to the SEET in 2013 based on 2012 earnings results and the SEET may have a material effect on our results of operations and financial condition.
On August 28, 2009, DP&L filed its application to establish reliability targets consistent with the most recent PUCO Electric Service and Safety Standards (ESSS). On March 29, 2010, DP&L entered into a settlement establishing the new reliability targets. This settlement was approved on July 29, 2010. According to the ESSS rules, all Ohio utilities are subject to financial penalties if the established targets are not met for two consecutive years.
Ohio Competitive Considerations and Proceedings
Since January 2001, DP&L’s electric customers have been permitted to choose their retail electric generation supplier. DP&L continues to have the exclusive right to provide delivery service in its state certified territory and the obligation to supply retail generation service to customers that do not choose an alternative supplier. The PUCO maintains jurisdiction over DP&L’s delivery of electricity, SSO and other retail electric services.
Market prices for power, as well as government aggregation initiatives within DP&L’s service territory, have led and may continue to lead to the entrance of additional competitors in our service territory. At June 30, 2012, there were 20 CRES providers in DP&L’s service territory. DPLER, an affiliated company and one of the 20 registered CRES providers, has been marketing supply services to DP&L customers. During 2011, DPLER accounted for approximately 5,731 million kWh of the total 6,593 million kWh supplied by CRES providers within DP&L’s service territory. For the six months ended June 30, 2012 DPLER accounted for approximately 1,540 million kWh of the total 2,500 million kWh supplied by CRES providers within DP&L’s service territory. Also during 2011, 27,812 customers with an annual energy usage of 862 million kWh were supplied by other CRES providers within DP&L’s service territory. The volume supplied by DPLER represents approximately 41% and 46% of DP&L’s total distribution sales volume during 2011 and for the six months ended June 30, 2012, respectively. The reduction to gross margin in 2011 as a result of customers switching to DPLER and other CRES providers was approximately $58 million and $104 million, for DPL and DP&L, respectively and $59 and $110 million for DPL and DP&L for the six months ended June 30, 2012, respectively. We currently cannot determine the extent to which customer switching to CRES providers will occur in the future and the effect this will have on our operations, but any additional switching could have a significant adverse effect on our future results of operations, financial condition and cash flows.
Several communities in DP&L’s service area have passed ordinances allowing the communities to become government aggregators for the purpose of offering alternative electric generation supplies to their citizens. To date,
a number of organizations have filed with the PUCO to initiate aggregation programs. If a number of the larger organizations move forward with aggregation, it could have a material effect on our earnings. See “Risk Factors” for more information.
In 2010, DPLER began providing CRES services to business customers in Ohio who are not in DP&L’s service territory. The incremental costs and revenues have not had a material effect on our results of operations, financial condition or cash flows.
DP&L entered into an economic development arrangement with its single largest electricity consumer. This arrangement was approved by the PUCO on June 8, 2011 and became effective in July 2011. Under Ohio law, DP&L is permitted to seek recovery of costs associated with economic development programs including foregone revenues from all customers. On October 26, 2011, the PUCO approved our Economic Development Rider, as filed, which is designed to recover costs associated with this and other economic development contracts and programs.
Federal Matters
Like other electric utilities and energy marketers, DP&L and DPLE may sell or purchase electric products on the wholesale market. DP&L and DPLE compete with other generators, power marketers, privately and municipally-owned electric utilities and rural electric cooperatives when selling electricity. The ability of DP&L and DPLE to sell this electricity will depend not only on the performance of our generating units, but also on how DP&L’s and DPLE’s prices, terms and conditions compare to those of other suppliers.
As part of Ohio’s electric deregulation law, all of the state’s investor-owned utilities are required to join a RTO. In October 2004, DP&L successfully integrated its high-voltage transmission lines into the PJM RTO. The role of the RTO is to administer a competitive wholesale market for electricity and ensure reliability of the transmission grid. PJM ensures the reliability of the high-voltage electric power system serving more than 50 million people in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia. PJM coordinates and directs the operation of the region’s transmission grid, administers the world’s largest competitive wholesale electricity market and plans regional transmission expansion improvements to maintain grid reliability and relieve congestion.
The PJM RPM capacity base residual auction for the 2015/2016 period cleared at a per megawatt price of $136/day for our RTO area. The per megawatt prices for the periods 2014/2015, 2013/2014, 2012/2013 and 2011/2012 were $126/day, $28/day, $16/day and $110/day, respectively, based on previous auctions. Future RPM auction results will be dependent not only on the overall supply and demand of generation and load, but may also be impacted by congestion as well as PJM’s business rules relating to bidding for demand response and energy efficiency resources in the RPM capacity auctions. Increases in customer switching causes more of the RPM capacity costs and revenues to be excluded from the RPM rider calculation. We cannot predict the outcome of future auctions or customer switching but if the current auction price is not sustained, our future results of operations, financial condition and cash flows could be materially adversely impacted.
As a member of PJM, DP&L is also subject to charges and costs associated with PJM operations as approved by the FERC. FERC orders issued in 2007 and thereafter regarding the allocation of costs of large transmission facilities within PJM which would result in additional costs being allocated to DP&L that, over time and depending on final costs and how quickly the facilities are constructed, could become material. DP&L filed a notice of appeal to the U.S. Court of Appeals, D.C. Circuit, which was consolidated with other appeals taken by other interested parties of the same FERC orders and the consolidated cases were assigned to the 7th Circuit. On August 6, 2009, the 7th Circuit ruled that the FERC had failed to provide a reasoned basis for the allocation method it had approved. Rehearings were filed by other interested litigants and denied by the Court, which then remanded the matter to the FERC for further proceedings. On January 21, 2010, the FERC issued a procedural order on remand establishing a paper hearing process under which PJM will make an informational filing. Subsequently, PJM and other parties, including DP&L, filed initial comments, testimony and recommendations and reply comments. FERC did not establish a deadline for its issuance of a substantive order and the matter is still pending. DP&L cannot predict the timing or the likely outcome of the proceeding. Until such time as FERC may act to approve a change in methodology, PJM will continue to apply the allocation methodology that had been approved by FERC in 2007. Although we continue to maintain that these costs should be borne by the beneficiaries of these projects and that
DP&L is not one of these beneficiaries, any new credits or additional costs resulting from the ultimate outcome of this proceeding will be reflected in DP&L’s TCRR rider which already includes these costs.
NERC is a FERC-certified electric reliability organization responsible for developing and enforcing mandatory reliability standards, including Critical Infrastructure Protection (CIP) reliability standards, across eight reliability regions. In June 2009, Reliability First Corporation (RFC), with responsibilities assigned to it by NERC over the reliability region that includes DP&L, commenced a routine audit of DP&L’s operations. The audit, which was for the period June 18, 2007 to June 25, 2009, evaluated DP&L’s compliance with 42 requirements in 18 NERC-reliability standards. DP&L is currently subject to a compliance audit at a minimum of once every three years as provided by the NERC Rules of Procedure. This audit was concluded in June 2009 and its findings revealed that DP&L had some Possible Alleged Violations (PAVs) associated with five NERC reliability requirements of various Standards. In response to the report, DP&L filed mitigation plans with RFC/NERC to address the PAVs. These mitigation plans were accepted by RFC/NERC. In July 2010, DP&L negotiated a settlement with NERC under which DP&L agreed to pay an immaterial amount in exchange for a resolution of all issues and obligations relating to the aforementioned PAVs. The settlement was approved on January 21, 2011 by the FERC.
Environmental Considerations
DPL’s and DP&L’s facilities and operations are subject to a wide range of federal, state and local environmental regulations and laws. The environmental issues that may effect us include:
· | The Federal CAA and state laws and regulations (including State Implementation Plans) which require compliance, obtaining permits and reporting as to air emissions. |
· | Litigation with federal and certain state governments and certain special interest groups regarding whether modifications to or maintenance of certain coal-fired generating plants require additional permitting or pollution control technology, or whether emissions from coal-fired generating plants cause or contribute to global climate changes. |
· | Rules and future rules issued by the USEPA and Ohio EPA that require substantial reductions in SO2, particulates, mercury, acid gases, NOx, and other air emissions. DP&L has installed emission control technology and is taking other measures to comply with required and anticipated reductions. |
· | Rules and future rules issued by the USEPA and Ohio EPA that require reporting and may require reductions of GHGs. |
· | Rules and future rules issued by the USEPA associated with the federal Clean Water Act, which prohibits the discharge of pollutants into waters of the United States except pursuant to appropriate permits. |
· | Solid and hazardous waste laws and regulations, which govern the management and disposal of certain waste. The majority of solid waste created from the combustion of coal and fossil fuels is fly ash and other coal combustion by-products. The EPA has previously determined that fly ash and other coal combustion byproducts are not hazardous waste subject to the Resource Conservation and Recovery Act (RCRA), but the EPA is reconsidering that determination. A change in determination or other additional regulation of fly ash or other coal combustion byproducts could significantly increase the costs of disposing of such ash byproducts. |
As well as imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. In the normal course of business, we have investigatory and remedial activities underway at these facilities to comply, or to determine compliance, with such regulations. We record liabilities for loss contingencies related to environmental matters when a loss is probable of occurring and can be reasonably estimated in accordance with the provisions of GAAP. Accordingly, we have estimated accruals for loss contingencies of approximately $3.4 million for environmental matters. We also have a number of unrecognized loss contingencies related to environmental matters that are disclosed in the paragraphs below. We evaluate the potential liability related to environmental matters quarterly and
may revise our estimates. Such revisions in the estimates of the potential liabilities could have a material adverse effect on our results of operations, financial condition or cash flows.
We have several other pending environmental matters associated with our coal-fired generation units. Together, these could result in significant capital and operations and maintenance expenditures for our coal-fired generation plants, and could result in the early retirement of our generation units that do not have SCR and FGD equipment installed. Currently, our coal-fired generation units at Hutchings and Beckjord do not have this emission-control equipment installed. DP&L owns 100% of the Hutchings plant and has a 50% interest in Beckjord Unit 6. In addition to environmental matters, the operation of our coal-fired generation plants could be affected by a multitude of other factors, including forecasted power, capacity and commodity prices, competition and the levels of customer switching, current and forecasted customer demand, cost of capital and regulatory and legislative developments, any of which could pose a potential triggering event for an impairment of our investments in the Hutchings and Beckjord units. On July 15, 2011, Duke Energy, a co-owner at the Beckjord Unit 6 facility, filed their Long-term Forecast Report with the PUCO. The plan indicated that Duke Energy plans to cease production at the Beckjord Station, including our commonly owned Unit 6, in December 2014. This was followed by a notification by Duke Energy to PJM, dated February 1, 2012, of a planned April 1, 2015 deactivation of this unit. We are depreciating Unit 6 through December 2014 and do not believe that any additional accruals or impairment charges are needed as a result of this decision. We are considering options for Hutchings Station, but have not yet made a final decision. We do not believe that any accruals or impairment charges are needed related to the Hutchings Station.
Environmental Matters Related to Air Quality
Clean Air Act Compliance
In 1990, the federal government amended the CAA to further regulate air pollution. Under the CAA, the USEPA sets limits on how much of a pollutant can be in the ambient air anywhere in the United States. The CAA allows individual states to have stronger pollution controls than those set under the CAA, but states are not allowed to have weaker pollution controls than those set for the whole country. The CAA has a material effect on our operations and such effects are detailed below with respect to certain programs under the CAA.
Cross-State Air Pollution Rule
The Clean Air Interstate Rule (CAIR) final rules were published on May 12, 2005. CAIR created an interstate trading program for annual NOx emission allowances and made modifications to an existing trading program for SO2. Appeals brought by various parties resulted in a decision by the U.S. Court of Appeals for the District of Columbia Circuit on July 11, 2008 to vacate CAIR and its associated Federal Implementation Plan (FIP). On December 23, 2008, the U.S. Court of Appeals issued an order on reconsideration that permits CAIR to remain in effect until the USEPA issues new regulations that would conform to the CAA requirements and the Court’s July 2008 decision.
In an attempt to conform to the Court’s decision, on July 6, 2010, the USEPA proposed the Clean Air Transport Rule (CATR). CATR was finalized as the Cross-State Air Pollution Rule (CSAPR) on July 6, 2011, but subsequent litigation has resulted in CSAPR’s implementation being delayed indefinitely. CSAPR creates four separate trading programs: two SO2 areas (Group 1 and Group 2); and two NOx reduction requirements (annual and ozone season). Group 1 states (16 states including Ohio) will have to meet a 2012 cap and additional reductions in 2014. Group 2 states (7 states) will only have to meet the 2012 cap. We do not believe the rule will have a material effect on our operations in 2012. The Ohio EPA has a State Implementation Plan (SIP) that incorporates the CAIR program requirements, which remain in effect pending judicial review of CSAPR. If CSAPR becomes effective, the USEPA is expected to institute a FIP in lieu of state SIPs and allow for the states to develop SIPs for approval as early as 2013. DP&L is unable to estimate the effect of the new requirements; however, CSAPR could have a material adverse effect on our operations.
Mercury and Other Hazardous Air Pollutants
On May 3, 2011, the USEPA published proposed Maximum Achievable Control Technology (MACT) standards for coal- and oil-fired electric generating units. The standards include new requirements for emissions of mercury and a number of other heavy metals. The USEPA Administrator signed the final rule, now called MATS
(Mercury and Air Toxics Standards), on December 16, 2011, and the rule was published in the Federal Register on February 16, 2012. Affected electric generating units (EGUs) will have to come into compliance with the new requirements by April 16, 2015, but may be granted an additional year contingent on Ohio EPA approval. DP&L is evaluating the costs that may be incurred to comply with the new requirement; however, MATS could have a material adverse effect on our results of operations and result in material compliance costs.
On April 29, 2010, the USEPA issued a proposed rule that would reduce emissions of toxic air pollutants from new and existing industrial, commercial and institutional boilers and process heaters at major and area source facilities. The final rule was published in the Federal Register on March 21, 2011. This regulation affects seven auxiliary boilers used for start-up purposes at DP&L’s generation facilities. The regulations contain emissions limitations, operating limitations and other requirements. In December 2011, the USEPA proposed additional changes to this rule and solicited comments. Compliance costs are not expected to be material to DP&L’s operations.
On May 3, 2010, the National Emissions Standards for Hazardous Air Pollutants for compression ignition (CI) reciprocating internal combustion engines (RICE) became effective. The units affected at DP&L are 18 diesel electric generating engines and eight emergency “black start” engines. The existing CI RICE units must comply by May 3, 2013. The regulations contain emissions limitations, operating limitations and other requirements. Compliance costs for DP&L’s operations are not expected to be material.
National Ambient Air Quality Standards
On January 5, 2005, the USEPA published its final non-attainment designations for the National Ambient Air Quality Standard (NAAQS) for Fine Particulate Matter 2.5 (PM 2.5). These designations included counties and partial counties in which DP&L operates and/or owns generating facilities. As of December 31, 2011, DP&L’s Stuart, Killen and Hutchings Stations were located in non-attainment areas for the annual PM 2.5 standard. There is a possibility that these areas will be re-designated as “attainment” for PM 2.5 within the next few calendar quarters and that the NAAQS for PM 2.5 will become more stringent. We cannot predict the effect the revisions to the PM 2.5 standard will have on DP&L’s financial condition or results of operations.
On September 16, 2009, the USEPA announced that it would reconsider the 2008 national ground level ozone standard. On September 2, 2011, the USEPA decided to postpone their revisiting of this standard until 2013. DP&L cannot determine the effect of this potential change, if any, on its operations.
Effective April 12, 2010, the USEPA implemented revisions to its primary NAAQS for nitrogen dioxide. This change may affect certain emission sources in heavy traffic areas like the I-75 corridor between Cincinnati and Dayton after 2016. Several of our facilities or co-owned facilities are within this area. DP&L cannot determine the effect of this potential change, if any, on its operations.
Effective August 23, 2010, the USEPA implemented revisions to its primary NAAQS for SO2 replacing the current 24-hour standard and annual standard with a one hour standard. DP&L cannot determine the effect of this potential change, if any, on its operations.
Regional Haze Program
On May 5, 2004, the USEPA issued its proposed regional haze rule, which addresses how states should determine the Best Available Retrofit Technology (BART) for sources covered under the regional haze rule. Final rules were published July 6, 2005, providing states with several options for determining whether sources in the state should be subject to BART. In the final rule, the USEPA made the determination that CAIR achieves greater progress than BART and may be used by states as a BART substitute and USEPA subsequently determined that if CSAPR becomes effective, it may be used to comply with BART requirements. In June 2012, the EPA published in the Federal Register a “limited disapproval” of Ohio’s proposed SIP relating to BART and proposed a FIP to replace certain CAIR-reliant provisions of Ohio’s SIP with CSAPR-reliant provisions. Numerous units owned and operated by us will be affected by BART. We cannot determine the extent of the impact until Ohio, in conjunction with USEPA, determines how BART will be implemented.
Carbon Emissions and Other Greenhouse Gases
In response to a U.S. Supreme Court decision that the USEPA has the authority to regulate CO2 emissions from motor vehicles, the USEPA made a finding that CO2 and certain other GHGs are pollutants under the CAA. Subsequently, under the CAA, USEPA determined that CO2 and other GHGs from motor vehicles threaten the health and welfare of future generations by contributing to climate change. This finding became effective in January 2010. On June 26, 2012, the U.S. Court of Appeals for the District of Columbia upheld this finding and other GHG regulations following challenges from industry and state opponents. On April 1, 2010, USEPA signed the “Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards” rule. Under USEPA’s view, this is the final action that renders CO2 and other GHGs “regulated air pollutants” under the CAA.
Under USEPA regulations finalized in May 2010 (referred to as the “Tailoring Rule”), the USEPA began regulating GHG emissions from certain stationary sources in January 2011. The Tailoring rule sets forth criteria for determining which facilities are required to obtain permits for their GHG emissions pursuant to the CAA Prevention of Significant Deterioration and Title V operating permit programs. Under the Tailoring Rule, permitting requirements are being phased in through successive steps that may expand the scope of covered sources over time. The USEPA has issued guidance on what the best available control technology entails for the control of GHGs and individual states are required to determine what controls are required for facilities on a case-by-case basis. The ultimate impact of the Tailoring Rule to DP&L cannot be determined at this time, but the cost of compliance could be material.
On April 13, 2012, the USEPA published its GHG standards for new electric generating units (EGUs) under CAA subsection 111(b), which would require certain new EGUs to meet a standard of 1,000 pounds of CO2 per megawatt-hour, a standard based on the emissions limitations achievable through natural gas combined cycle generation. The proposal anticipates that affected coal-fired units would need to install carbon capture and storage or other expensive CO2 emission control technology to meet the standard. Furthermore, the USEPA may propose and promulgate guidelines for states to address GHG standards for existing EGUs under CAA subsection 111(d). These letter rules may focus on energy efficiency improvements at power plants. We cannot predict the effect of these standards, if any, on DP&L’s operations.
Approximately 98% of the energy we produce is generated by coal. DP&L’s share of CO2 emissions at generating stations we own and co-own is approximately 16 million tons annually. Further GHG legislation or regulation finalized at a future date could have a significant effect on DP&L’s operations and costs, which could adversely affect our net income, cash flows and financial condition. However, due to the uncertainty associated with such legislation or regulation, we cannot predict the final outcome or the financial effect that such legislation or regulation may have on DP&L.
On September 22, 2009, the USEPA issued a final rule for mandatory reporting of GHGs from large sources that emit 25,000 metric tons per year or more of CO2, including electric generating units. DP&L’s first report to the USEPA was submitted prior to the September 30, 2011 due date for 2010 emissions. This reporting rule will guide development of policies and programs to reduce emissions. DP&L does not anticipate that this reporting rule will result in any significant cost or other effect on current operations.
Litigation, Notices of Violation and Other Matters Related to Air Quality
Litigation Involving Co-Owned Plants
On June 20, 2011, the U.S. Supreme Court ruled that the USEPA regulation of GHGs under the CAA displaced any right that plaintiffs may have had to seek similar regulation through federal common law litigation in the court system. Although we are not named as a party to these lawsuits, DP&L is a co-owner of coal-fired plants with Duke Energy and AEP (or their subsidiaries) that could have been affected by the outcome of these lawsuits or similar suits that may have been filed against other electric power companies, including DP&L. Because the issue was not squarely before it, the U.S. Supreme Court did not rule against the portion of plaintiffs’ original suits that sought relief under state law.
As a result of a 2008 consent decree entered into with the Sierra Club and approved by the U.S. District Court for the Southern District of Ohio, DP&L and the other owners of the J.M. Stuart generating station are subject to certain specified emission targets related to NOx, SO2 and particulate matter. The consent decree also includes commitments for energy efficiency and renewable energy activities. An amendment to the consent decree was entered into and approved in 2010 to clarify how emissions would be computed during malfunctions. Continued compliance with the consent decree, as amended, is not expected to have a material effect on DP&L’s results of operations, financial condition or cash flows in the future.
Notices of Violation Involving Co-Owned Plants
In November 1999, the USEPA filed civil complaints and NOVs against operators and owners of certain generation facilities for alleged violations of the CAA. Generation units operated by Duke Energy (Beckjord Unit 6) and CSP (Conesville Unit 4) and co-owned by DP&L were referenced in these actions. Although DP&L was not identified in the NOVs, civil complaints or state actions, the results of such proceedings could materially affect DP&L’s co-owned plants.
In June 2000, the USEPA issued a NOV to the DP&L-operated J.M. Stuart generating station (co-owned by DP&L, Duke Energy and CSP) for alleged violations of the CAA. The NOV contained allegations consistent with NOVs and complaints that the USEPA had brought against numerous other coal-fired utilities in the Midwest. The NOV indicated the USEPA may: (1) issue an order requiring compliance with the requirements of the Ohio SIP; or (2) bring a civil action seeking injunctive relief and civil penalties of up to $27,500 per day for each violation. To date, neither action has been taken. DP&L cannot predict the outcome of this matter.
In December 2007, the Ohio EPA issued a NOV to the DP&L-operated Killen generating station (co-owned by DP&L and Duke Energy) for alleged violations of the CAA. The NOV alleged deficiencies in the continuous monitoring of opacity. We submitted a compliance plan to the Ohio EPA on December 19, 2007. To date, no further actions have been taken by the Ohio EPA.
On March 13, 2008, Duke Energy, the operator of the Zimmer generating station, received a NOV and a Finding of Violation (FOV) from the USEPA alleging violations of the CAA, the Ohio State Implementation Program (SIP) and permits for the Station in areas including SO2, opacity and increased heat input. A second NOV and FOV with similar allegations was issued on November 4, 2010. Also in 2010, USEPA issued an NOV to Zimmer for excess emissions. DP&L is a co-owner of the Zimmer generating station and could be affected by the eventual resolution of these matters. Duke Energy is expected to act on behalf of itself and the co-owners with respect to these matters. DP&L is unable to predict the outcome of these matters.
Notices of Violation Involving Wholly-Owned Plants
In 2007, the Ohio EPA and the USEPA issued NOVs to DP&L for alleged violations of the CAA at the O.H. Hutchings Station. The NOVs’ alleged deficiencies relate to stack opacity and particulate emissions. Discussions are under way with the USEPA, the U.S. Department of Justice and Ohio EPA. On November 18, 2009, the USEPA issued an NOV to DP&L for alleged NSR violations of the CAA at the O.H. Hutchings Station relating to capital projects performed in 2001 involving Unit 3 and Unit 6. DP&L does not believe that the two projects described in the NOV were modifications subject to NSR. DP&L is engaged in discussions with the USEPA and Justice Department to resolve these matters, but DP&L is unable to determine the timing, costs or method by which these issues may be resolved. The Ohio EPA is kept apprised of these discussions.
Environmental Matters Related to Water Quality, Waste Disposal and Ash Ponds
Clean Water Act – Regulation of Water Intake
On July 9, 2004, the USEPA issued final rules pursuant to the Clean Water Act governing existing facilities that have cooling water intake structures. The rules require an assessment of impingement and/or entrainment of organisms as a result of cooling water withdrawal. A number of parties appealed the rules. In April 2009, the U.S. Supreme Court ruled that the USEPA did have the authority to compare costs with benefits in determining best technology available. The USEPA released new proposed regulations on March 28, 2011, which were published in
the Federal Register on April 20, 2011. We submitted comments to the proposed regulations on August 17, 2011. The final rules are expected to be in place by mid-2012. We do not yet know the impact these proposed rules will have on our operations.
Clean Water Act – Regulation of Water Discharge
In December 2006, we submitted an application for the renewal of the Stuart Station NPDES Permit that was due to expire on June 30, 2007. In July 2007, we received a draft permit proposing to continue our authority to discharge water from the station into the Ohio River. On February 5, 2008, we received a letter from the Ohio EPA indicating that they intended to impose a compliance schedule as part of the final Permit, that requires us to implement one of two diffuser options for the discharge of water from the station into the Ohio River as identified in a thermal discharge study completed during the previous permit term. Subsequently, DP&L and the Ohio EPA reached an agreement to allow DP&L to restrict public access to the water discharge area as an alternative to installing one of the diffuser options. The Ohio EPA issued a revised draft permit that was received on November 12, 2008. In December 2008, the USEPA requested that the Ohio EPA provide additional information regarding the thermal discharge in the draft permit. In June 2009, DP&L provided information to the USEPA in response to their request to the Ohio EPA. In September 2010, the USEPA formally objected to a revised permit provided by Ohio EPA due to questions regarding the basis for the alternate thermal limitation. In December 2010, DP&L requested a public hearing on the objection, which was held on March 23, 2011. We participated in and presented our position on the issue at the hearing and in written comments submitted on April 28, 2011. In a letter to the Ohio EPA dated September 28, 2011, the USEPA reaffirmed its objection to the revised permit as previously drafted by the Ohio EPA. This reaffirmation stipulated that if the Ohio EPA does not re-draft the permit to address the USEPA’s objection, then the authority for issuing the permit will pass to the USEPA. The Ohio EPA issued another draft permit in December 2011 and a public hearing was held on February 2, 2012. The draft permit would require DP&L, over the 54 months following issuance of a final permit, to take undefined actions to lower the temperature of its discharged water to a level unachievable by the station under its current design or alternatively make other significant modifications to the cooling water system. DP&L submitted comments to the draft permit and is considering legal options. Depending on the outcome of the process, the effects could be material on DP&L’s operation.
In September 2009, the USEPA announced that it will be revising technology-based regulations governing water discharges from steam electric generating facilities. The rulemaking included the collection of information via an industry-wide questionnaire as well as targeted water sampling efforts at selected facilities. It is anticipated that the USEPA will release a proposed rule by November 2012 with a final regulation in place by early 2014. At present, DP&L is unable to predict the impact this rulemaking will have on its operations.
Regulation of Waste Disposal
In September 2002, DP&L and other parties received a special notice that the USEPA considers us to be a PRP for the clean-up of hazardous substances at the South Dayton Dump landfill site. In August 2005, DP&L and other parties received a general notice regarding the performance of a Remedial Investigation and Feasibility Study (RI/FS) under a Superfund Alternative Approach. In October 2005, DP&L received a special notice letter inviting it to enter into negotiations with the USEPA to conduct the RI/FS. No recent activity has occurred with respect to that notice or PRP status. However, on August 25, 2009, the USEPA issued an Administrative Order requiring that access to DP&L’s service center building site, which is across the street from the landfill site, be given to the USEPA and the existing PRP group to help determine the extent of the landfill site’s contamination as well as to assess whether certain chemicals used at the service center building site might have migrated through groundwater to the landfill site. DP&L granted such access and drilling of soil borings and installation of monitoring wells occurred in late 2009 and early 2010. On May 24, 2010, three members of the existing PRP group, Hobart Corporation, Kelsey-Hayes Company and NCR Corporation, filed a civil complaint in the United States District Court for the Southern District of Ohio against DP&L and numerous other defendants alleging that DP&L and the other defendants contributed to the contamination at the South Dayton Dump landfill site and seeking reimbursement of the PRP group’s costs associated with the investigation and remediation of the site. On February 10, 2011, the Court dismissed claims against DP&L that related to allegations that chemicals used by DP&L at its service center contributed to the landfill site’s contamination. The Court, however, did not dismiss claims alleging financial responsibility for remediation costs based on hazardous substances from DP&L that were allegedly directly
delivered by truck to the landfill. Discovery, including depositions of past and present DP&L employees, is ongoing. While DP&L is unable to predict the outcome of these matters, if DP&L were required to contribute to the clean-up of the site, it could have a material adverse effect on us.
In December 2003, DP&L and other parties received a special notice that the USEPA considers us to be a PRP for the clean-up of hazardous substances at the Tremont City landfill site. Information available to DP&L does not demonstrate that it contributed hazardous substances to the site. While DP&L is unable to predict the outcome of this matter, if DP&L were required to contribute to the clean-up of the site, it could have a material adverse effect on us.
On April 7, 2010, the USEPA published an Advance Notice of Proposed Rulemaking announcing that it is reassessing existing regulations governing the use and distribution in commerce of polychlorinated biphenyls (PCBs). While this reassessment is in the early stages and the USEPA is seeking information from potentially affected parties on how it should proceed, the outcome may have a material effect on DP&L. The USEPA has indicated that a proposed rule will be released in late 2012. At present, DP&L is unable to predict the impact this initiative will have on its operations.
Regulation of Ash Ponds
In March 2009, the USEPA, through a formal Information Collection Request, collected information on ash pond facilities across the country, including those at Killen and J.M. Stuart Stations. Subsequently, the USEPA collected similar information for O.H. Hutchings Station.
In August 2010, the USEPA conducted an inspection of the O.H. Hutchings Station ash ponds. In June 2011, the USEPA issued a final report from the inspection including recommendations relative to the O.H. Hutchings Station ash ponds. DP&L is unable to predict whether there will be additional USEPA action relative to DP&L’s proposed plan or the effect on operations that might arise under a different plan.
In June 2011, the USEPA conducted an inspection of the Killen Station ash ponds. DP&L is unable to predict the outcome this inspection will have on its operations.
There has been increasing advocacy to regulate coal combustion byproducts under the Resource Conservation Recovery Act (RCRA). On June 21, 2010, the USEPA published a proposed rule seeking comments on two options under consideration for the regulation of coal combustion byproducts including regulating the material as a hazardous waste under RCRA Subtitle C or as a solid waste under RCRA Subtitle D. The USEPA anticipates issuing a final rule on this topic in late 2012. DP&L is unable to predict the financial effect of this regulation, but if coal combustion byproducts are regulated as hazardous waste, it is expected to have a material adverse effect on DP&L’s operations.
Notice of Violation Involving Co-Owned Plants
On September 9, 2011, DP&L received a notice of violation from the USEPA with respect to its co-owned J.M. Stuart generating station based on a compliance evaluation inspection conducted by the USEPA and Ohio EPA in 2009. The notice alleged non-compliance by DP&L with certain provisions of the RCRA, the Clean Water Act National Pollutant Discharge Elimination System permit program and the station’s storm water pollution prevention plan. The notice requested that DP&L respond with the actions it has subsequently taken or plans to take to remedy the USEPA’s findings and ensure that further violations will not occur. Based on its review of the findings, although there can be no assurance, we believe that the notice will not result in any material effect on DP&L’s results of operations, financial condition or cash flow.
In April 2012, DP&L received an NOV related to the construction of the Carter Hollow landfill at the J.M. Stuart station. The NOV indicated that construction activities caused sediment to flow into downstream creeks. DP&L expects to install sedimentation ponds as part of the runoff control measures to address this issue. We expect the impact of this NOV to be immaterial.
Legal and Other Matters
In February 2007, DP&L filed a lawsuit against a coal supplier seeking damages incurred due to the supplier’s failure to supply approximately 1.5 million tons of coal to two commonly owned plants under a coal supply agreement, of which approximately 570 thousand tons was DP&L’s share. DP&L obtained replacement coal to meet its needs. The supplier has denied liability, and is currently in federal bankruptcy proceedings in which DP&L is participating as an unsecured creditor. DP&L is unable to determine the ultimate resolution of this matter. DP&L has not recorded any assets relating to possible recovery of costs in this lawsuit.
In connection with DP&L and other utilities joining PJM, in 2006, the FERC ordered utilities to eliminate certain charges to implement transitional payments, known as SECA, effective December 1, 2004 through March 31, 2006, subject to refund. Through this proceeding, DP&L was obligated to pay SECA charges to other utilities, but received a net benefit from these transitional payments. A hearing was held and an initial decision was issued in August 2006. A final FERC order on this issue was issued on May 21, 2010 that substantially supports DP&L’s and other utilities’ position that SECA obligations should be paid by parties that used the transmission system during the timeframe stated above. Prior to this final order being issued, DP&L entered into a significant number of bilateral settlement agreements with certain parties to resolve the matter, which by design will be unaffected by the final decision. On July 5, 2012, a Stipulation was executed and filed with the FERC that resolves SECA claims against BP Energy Company (“BP”) and DP&L, AEP (and its subsidiaries On July 5, 2012, a Stipulation was executed and filed with the FERC that resolves SECA claims against BP Energy Company (“BP”) and DP&L, AEP (and its subsidiaries) and Exelon Corporation (and its subsidiaries). If the Stipulation is approved, DP&L would receive approximately $14.6 million from BP. DP&L will record the settlement of the BP claims once FERC approval is received. With respect to these claims, DP&L management has deferred $18.1 million and $17.8 million as of June 30, 2012 and December 31, 2011, respectively, as other deferred credits representing the amount of unearned income and interest where the earnings process is not complete. The amount at June 30, 2012 and December 31, 2011 includes estimated earnings and interest of $5.4 million and $5.2 million, respectively. On September 30, 2011, the FERC issued two SECA-related orders that affirmed an earlier order issued in 2010 by denying the rehearing requests that a number of different parties, including DP&L, had filed. These orders are now final, subject to possible appellate court review. These orders do not affect settlements that had been reached with other parties that owed SECA revenues to DP&L or were recipients of amounts paid by DP&L. For other parties that had not previously settled with DP&L, the exact timing and amounts of any payments that would be made or received by DP&L under these orders is still uncertain.
Lawsuits were filed in connection with the Merger seeking, among other things, one or more of the following: to enjoin consummation of the Merger until certain conditions were met, to rescind the Merger or for rescissory damages, or to commence a sale process and/or obtain an alternative transaction or to recover an unspecified amount of other damages and costs, including attorneys’ fees and expenses, or a constructive trust or an accounting from the individual defendants for benefits they allegedly obtained as a result of their alleged breach of duty. All of these lawsuits, except one, were resolved and/or dismissed prior to the March 28, 2012 filing of our Form 10-K for the fiscal year ending December 31, 2011, and were discussed in that and previous reports we filed. The last of these lawsuits was dismissed on March 29, 2012.
Also refer to Notes 2 and 13 of Notes to DPL’s Condensed Consolidated Financial Statements for additional information surrounding the Merger and certain related legal matters.
Capital Expenditures for Environmental Matters
DP&L’s environmental capital expenditures were approximately $12 million, $12 million and $21 million in 2011, 2010 and 2009, respectively. DP&L has budgeted $15 million in environmental related capital expenditures for 2012.
Electric Sales and Revenues
The following table sets forth DPL’s electric sales and revenues for the period November 28, 2011 (the Merger date) through December 31, 2011 (Successor), the period January 1, 2011 through November 27, 2011 and the years ended December 31, 2010 and 2009 (Predecessor), respectively.
In the following table, we have included the combined Predecessor and Successor statistical information and results of operations. Such combined presentation is considered to be a non-GAAP disclosure. We have included such disclosure because we believe it facilitates the comparison of 2011 operating and financial performance to 2010 and 2009, and because the core operations of DPL have not changed as a result of the Merger.
DPL | ||||||||||||||||||||
Combined | Successor | Predecessor | ||||||||||||||||||
Year ended December 31, 2011 | November 28, 2011 through December 31, 2011 | January 1, 2011 through November 27, 2011 | Years ended December 31, | |||||||||||||||||
2010 | 2009 | |||||||||||||||||||
Electric sales (millions of kWh) | ||||||||||||||||||||
Residential | 5,257 | 506 | 4,751 | 5,522 | 5,120 | |||||||||||||||
Commercial | 3,956 | 343 | 3,613 | 3,842 | 3,678 | |||||||||||||||
Industrial | 3,482 | 271 | 3,211 | 3,605 | 3,353 | |||||||||||||||
Other retail | 1,410 | 116 | 1,294 | 1,437 | 1,386 | |||||||||||||||
Total retail | 14,105 | 1,236 | 12,869 | 14,406 | 13,537 | |||||||||||||||
Wholesale | 2,277 | 125 | 2,152 | 2,831 | 3,130 | |||||||||||||||
Total | 16,382 | 1,361 | 15,021 | 17,237 | 16,667 | |||||||||||||||
Operating revenues ($ in thousands) | ||||||||||||||||||||
Residential | $ | 671,301 | $ | 64,672 | $ | 606,629 | $ | 662,507 | $ | 536,123 | ||||||||||
Commercial | 375,781 | 32,544 | 343,237 | 369,934 | 318,502 | |||||||||||||||
Industrial | 256,270 | 19,055 | 237,215 | 252,361 | 220,701 | |||||||||||||||
Other retail | 108,391 | 8,061 | 100,330 | 110,150 | 95,459 | |||||||||||||||
Other miscellaneous revenues | 17,295 | 2,020 | 15,275 | 9,815 | 8,766 | |||||||||||||||
Total retail | 1,429,038 | 126,352 | 1,302,686 | 1,404,767 | 1,179,551 | |||||||||||||||
Wholesale | 129,669 | 8,371 | 121,298 | 142,149 | 122,519 | |||||||||||||||
RTO revenues | 261,368 | 20,430 | 240,938 | 272,832 | 225,677 | |||||||||||||||
Other revenues | 7,768 | 1,775 | 5,993 | 11,697 | 11,689 | |||||||||||||||
Total | $ | 1,827,843 | $ | 156,928 | $ | 1,670,915 | $ | 1,831,445 | $ | 1,539,436 | ||||||||||
Electric customers at end of period | ||||||||||||||||||||
Residential | 454,697 | 455,572 | 456,144 | |||||||||||||||||
Commercial | 53,341 | 50,764 | 50,141 | |||||||||||||||||
Industrial | 1,906 | 1,800 | 1,773 | |||||||||||||||||
Other | 6,943 | 6,742 | 6,577 | |||||||||||||||||
Total | 516,887 | 514,878 | 514,635 |
DPL is structured in two operating segments, DP&L and DPLER. See Note 19 of Notes to DPL’s Consolidated Financial Statements and Note 14 of Notes to DPL’s Condensed Consolidated Financial Statements for more information on DPL’s segments. The following tables set forth DP&L’s and DPLER’s electric sales and revenues for the years ended December 31, 2011, 2010 and 2009, respectively.
DP&L (a) | ||||||||||||
2011 | 2010 | 2009 | ||||||||||
Electric sales (millions of kWh) | ||||||||||||
Residential | 5,257 | 5,522 | 5,120 | |||||||||
Commercial | 3,208 | 3,741 | 3,678 | |||||||||
Industrial | 3,313 | 3,582 | 3,353 | |||||||||
Other retail | 1,381 | 1,432 | 1,386 | |||||||||
Total retail | 13,159 | 14,277 | 13,537 | |||||||||
Wholesale | 2,440 | 2,806 | 3,053 | |||||||||
Total | 15,599 | 17,083 | 16,590 | |||||||||
Operating revenues ($ in thousands) | ||||||||||||
Residential | 662,919 | 662,466 | 536,116 | |||||||||
Commercial | 204,465 | 289,628 | 314,697 | |||||||||
Industrial | 66,556 | 110,115 | 178,534 | |||||||||
Other retail | 55,694 | 60,840 | 79,424 | |||||||||
Other miscellaneous revenues | 17,744 | 10,723 | 8,954 | |||||||||
Total retail | 1,007,378 | 1,133,772 | 1,117,725 | |||||||||
Wholesale | 441,199 | 365,798 | 181,871 | |||||||||
RTO revenues | 229,143 | 239,274 | 201,254 | |||||||||
Other revenues | - | - | - | |||||||||
Total | 1,677,720 | 1,738,844 | 1,500,850 | |||||||||
Electric customers at end of period | ||||||||||||
Residential | 454,697 | 455,572 | 456,144 | |||||||||
Commercial | 50,123 | 50,155 | 50,141 | |||||||||
Industrial | 1,757 | 1,769 | 1,773 | |||||||||
Other | 6,806 | 6,739 | 6,577 | |||||||||
Total | 513,383 | 514,235 | 514,635 |
DPLER (b) | ||||||||||||
2011 | 2010 | 2009 | ||||||||||
Electric sales (millions of kWh) | ||||||||||||
Residential | 113 | 1 | - | |||||||||
Commercial | 2,579 | 1,194 | 68 | |||||||||
Industrial | 3,102 | 2,476 | 983 | |||||||||
Other retail | 883 | 875 | 413 | |||||||||
Total retail | 6,677 | 4,546 | 1,464 | |||||||||
Wholesale | - | - | - | |||||||||
Total | 6,677 | 4,546 | 1,464 | |||||||||
Operating revenues ($ in thousands) | ||||||||||||
Residential | $ | 8,381 | $ | 41 | $ | - | ||||||
Commercial | 171,316 | 80,307 | 3,802 | |||||||||
Industrial | 189,715 | 142,246 | 42,165 | |||||||||
Other retail | 56,344 | 52,811 | 18,871 | |||||||||
Other miscellaneous revenues | 252 | 57 | - |
DP&L (b) | ||||||||||||
2011 | 2010 | 2009 | ||||||||||
Total retail | 426,008 | 275,462 | 64,838 | |||||||||
Wholesale | 65 | - | - | |||||||||
RTO revenues | 2,407 | 1,503 | 615 | |||||||||
Other (mark-to-market gains / (losses)) | (3,068 | ) | 27 | 95 | ||||||||
Total | $ | 425,412 | $ | 276,992 | $ | 65,548 | ||||||
Electric customers at end of period | ||||||||||||
Residential | 22,314 | 33 | - | |||||||||
Commercial | 14,321 | 7,205 | 223 | |||||||||
Industrial | 772 | 564 | 44 | |||||||||
Other | 2,764 | 1,200 | 123 | |||||||||
Total | 40,171 | 9,002 | 390 |
(a) | DP&L sold 5,731 million kWh, 4,417 million kWh and 1,464 million kWh of power to DPLER (a subsidiary of DPL) for the years ended December 31, 2011, December 31, 2010 and 2009, respectively, which are not included in DP&L wholesale sales volumes in the chart above. These kWh sales also relate to DP&L retail customers within the DP&L service territory for distribution services and their inclusion in wholesale sales would result in a double counting of kWh volume. The dollars of operating revenues associated with these sales are classified as wholesale revenues on DP&L's Financial Statements and retail revenues on DPL’s Consolidated Financial Statements. |
(b) | This chart includes all sales of DPLER, both within and outside of the DP&L service territory. |
The following table sets forth electric sales and billed electric customers for the three and six months ended June 30, 2012 and 2011:
DPL | DP&L(a) | DPLER(b)(c) | ||||||||||||||||||||||
Three Months Ended June 30, | Three Months Ended June 30, | Three Months Ended June 30, | ||||||||||||||||||||||
2012 Successor | 2011 Predecessor | 2012 | 2011 | 2012 | 2011 | |||||||||||||||||||
Electric sales (millions of kWh) | 3,494 | 3,861 | 3,202 | 3,638 | 1,871 | 1,669 | ||||||||||||||||||
Billed electric customers (end of period) | 532,502 | 516,290 | 512,691 | 513,123 | 69,968 | 15,200 |
DPL | DP&L(a) | DPLER(b) (c) | ||||||||||||||||||||||
Six Months Ended June 30, | Six Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
2012 Successor | 2011 Predecessor | 2012 | 2011 | 2012 | 2011 | |||||||||||||||||||
Electric sales (millions of kWh) | 7,251 | 8,114 | 6,727 | 7,812 | 3,617 | 3,141 | ||||||||||||||||||
Billed electric customers (end of period) | 532,502 | 516,290 | 512,691 | 513,123 | 69,968 | 15,200 |
(a) | This chart contains electric sales from DP&L’s generation and purchased power. DP&L sold 1,540 million kWh and 1,419 million kWh of power to DPLER during the three months ended June 30, 2012 and 2011, respectively, and 2,997 million kWh and 2,763 million kWh of power to DPLER during the six months ended June 30, 2012 and 2011, respectively. |
(b) | This chart includes all sales of DPLER and MC Squared, both within and outside of the DP&L service territory. |
(c) | Does not include approximately 29,000 customers recently enrolled by MC Squared under various governmental aggregation agreements at June 30, 2012 that have not yet been physically billed. |
The following table sets forth information regarding our officers and directors as of August 24, 2012:
Name | Age | Position |
Andrew M. Vesey | 56 | Director and Chairman of the Board of DPL and DP&L |
Philip R. Herrington | 50 | Director, President and Chief Executive Officer of DPL and DP&L |
Brian A. Miller | 46 | Director of DPL and DP&L |
Mary S. Stawikey | 61 | Director of DPL |
Gregory S. Campbell | 56 | Vice President and Controller of DPL and DP&L |
Geoffrey M. Gailey | 57 | Acting Vice President, Human Resources and Administration, of DPL and DP&L |
Craig L. Jackson | 39 | Senior Vice President and Chief Financial Officer of DPL and DP&L |
Scott J. Kelly | 47 | Senior Vice President of DPL and DP&L |
Dennis A. Lantzy | 64 | Senior Vice President, Generation, of DPL and DP&L |
Jeffrey K. MacKay | 34 | Vice President and Treasurer of DPL and DP&L |
Teresa F. Marrinan | 50 | Senior Vice President, Competitive Market Services, of DPL and DP&L |
Bryce W. Nickel | 55 | Senior Vice President, Service Operations, of DPL and DP&L |
Thomas A. Raga | 47 | Vice President, External Affairs, of DPL and DP&L |
Timothy G. Rice | 57 | Vice President, Acting General Counsel and Corporate Secretary of DPL and DP&L |
Andrew M. Vesey joined the Board of Directors of DPL and DP&L as Chairman in November 2011. Mr. Vesey served as Acting Chief Executive Officer of DPL and DP&L from December 2011 to March 2012. Mr. Vesey currently also serves as Chief Operating Officer, Global Utilities, and Executive Vice President of The AES Corporation, the ultimate parent company of DPL, and has held those positions since October of 2011. Prior to assuming those positions at The AES Corporation, Mr. Vesey was Executive Vice President and Regional President of Latin America and Africa since April of 2009, Executive Vice President and Regional President for Latin America from March 2008 through March 2009, and Chief Operating Officer for Latin America from July 2007 through February 2008. Mr. Vesey also served as Vice President and Group Manager for AES Latin America, DR-CAFTA Region, Vice President of the Global Business Transformation Group, and Vice President of the Integrated Utilities Development Group. Mr. Vesey is also Chairman of the AES Sul, AES Tiete, Indianapolis Power & Light Company, and IPALCO Enterprises, Inc. Boards and serves on the Boards of AES Sonel, Companhia Brasiliana de Energia, and AES Elpa. In addition, Mr. Vesey is a member of the Board of the Corporate Council of Africa, Trust for the Americas, and the Institute of the Americas. Prior to joining The AES Corporation in 2004, Mr. Vesey was a Managing Director of the Utility Finance and Regulatory Advisory Practice at FTI Consulting Inc., a partner in the Energy, Chemicals and Utilities Practice of Ernst & Young LLP, and CEO and Managing Director of Citipower Pty of Melbourne, Australia. He received his BA in Economics and a BS in Mechanical Engineering from Union College in Schenectady, New York and his MS from New York University. Through his extensive experiences and executive positions in the energy industry, including serving on the Board of Directors of companies similar to DPL and DP&L, Mr. Vesey brings an in-depth knowledge of the energy industry and strong leadership skills to the DPL Board of Directors.
Philip R. Herrington was appointed President and Chief Executive Officer, and joined the Board of Directors, of DPL and DP&L in March 2012. He previously held executive positions with the wind generation business of The AES Corporation, the ultimate parent company of DPL, where he served as President of that business from August 2011 to March 2012 and Vice President, Operations and Asset Management, from December 2010 to August 2011. In these positions, Mr. Herrington oversaw operations and management of The AES Corporation’s worldwide wind generation portfolio. Before joining The AES Corporation, Mr. Herrington spent 17 years at Edison Mission Energy (a subsidiary of Edison International and a holding company with subsidiaries and affiliates engaged in the business of developing, owning, leasing and/or operating co-generation and other energy-related projects), where he served in various leadership positions in development, asset management and engineering, including Vice President, Commercial Management and Vice President, Business Development. Prior to that, Mr. Herrington was a project manager with Monsanto Chemical’s engineering group and also served as a naval officer aboard nuclear submarines. Mr. Herrington received a Bachelor of Science degree in Chemical Engineering from the University of California at Santa Barbara and an MBA from the University of Southern California’s Marshal School of Business. Mr. Herrington joined DPL in 2012 and brings strong leadership skills to the Board and the Company having served in various executive management positions in the energy industry prior to joining DPL.
Brian A. Miller joined the Board of Directors of DPL and DP&L in November 2011. Mr. Miller also serves as Executive Vice President, General Counsel, and Corporate Secretary of The AES Corporation, the ultimate parent company of DPL. Mr. Miller joined The AES Corporation in 2001 and has served in various positions, including Vice President, Deputy General Counsel, Corporate Secretary, General Counsel for North America and Assistant General Counsel. In March of 2008, Mr. Miller joined the Board of AES Solar Energy, Ltd. and AES Solar Power, LLC, joint ventures between The AES Corporation and Riverstone Holdings LLC. In 2009, he joined the Board of AgCert International Limited and AgCert Canada Holding Limited. In 2010, Mr. Miller joined the Board of AES Entek, a joint venture that will develop and operate power projects in Turkey, between The AES Corporation and Koc Holdings. Prior to joining The AES Corporation, he was an attorney with the law firm Chadbourne & Parke, LLP. Mr. Miller received a bachelor’s degree in History and Economics from Boston College and holds a Juris Doctorate from the University of Connecticut School Of Law. With over 10 years working at The AES Corporation and extensive executive and legal experience in the energy industry, Mr. Miller brings strong experience, risk management and leadership skills to the DPL Board of Directors.
Mary S. Stawikey joined the Board of Directors of DPL as independent director in November 2011. Ms. Stawikey is Vice President – Client Services of Corporation Services Company and has held that position since July 1996. She previously served as Client Support Manager in the Equities Division of Goldman Sachs from April 1984 to July 1995. Ms. Stawikey has also served as an independent director on several special purpose entities.
Gregory S. Campbell was appointed Vice President and Controller, DPL and DP&L in July 2012. He previously served as Director of Accounting Policy and Reporting, DPL and DP&L from June 2008 to June 2012. Prior to that, Mr. Campbell worked for 27 years at American Electric Power Company, Inc. (an energy services company) and its affiliates, where he held various positions working in and overseeing accounting operations, including Manager of Budgeting and Managerial Reporting, Accounting Director, Divisional Controller and Director of Accounting Policy and Research. He also has four years of experience working for two large public accounting firms. Mr. Campbell joined us in 2008.
Geoffrey M. Gailey was appointed Acting Vice President, Human Resources and Administration, DPL and DP&L in January 2012. Mr. Gailey has also served as Vice President of Human Resources at Indianapolis Power & Light Company, another wholly-owned subsidiary of The AES Corporation, since March 2008, where he is responsible for all human resource functions. He previously served as Vice President of Human Resources at The Fonda Group from August 1998 to March 2008 and Vice President of Human Resources at the Solo Cup Company from February 2004 to October 2007, and oversaw all human resource responsibilities for these two food service products companies. Mr. Gailey has served on the boards of several non-profit organizations, including Gleaners Food Bank (president) and the Greater Indianapolis Literacy League. He currently serves on the board and executive committee of United Way of Central Indiana and the IVY Tech Community Engagement Committee. Mr. Gailey joined us in January 2012.
Craig L. Jackson was appointed Senior Vice President and Chief Financial Officer of DPL and DP&L in July 2012. He previously served as Senior Vice President, Chief Financial Officer and Treasurer of DPL and DP&L from May 2012 to July 2012; Vice President and Treasurer, DPL and DP&L from December 2010 to May 2012; Vice President and Assistant Treasurer, DPL and DP&L from January 2010 to December 2010; Assistant Treasurer, DPL and DP&L from June 2008 to January 2010; Director, Financial Planning and Business Development, DPL and DP&L from June 2007 to June 2008; and Manager, Financial Planning and Risk, DPL and DP&L from July 2004 to May 2007. Mr. Jackson serves as Board Chairman of Rebuilding Together Dayton. Mr. Jackson joined DPL in 2004.
Scott J. Kelly was appointed Senior Vice President, Shared Services, DPL and DP&L in May 2011. He previously served as Senior Vice President, DPL and DP&L, from February 2010 to May 2011; Senior Vice President, Service Operations, DPL and DP&L from July 2007 to February 2010; Vice President, Service Operations, DPL and DP&L from March 2007 to July 2007 (oversight of all customer service operations); and Director – Engineering and Business Development, DPL and DP&L from January 2002 to February 2007 (responsible for all functions of system and central dispatch operations, design engineering and major accounts). In addition, Mr. Kelly has served in other supervisory positions since joining DP&L in 1994. Mr. Kelly also serves as a board member of Big Brothers/Big Sisters of the Greater Miami Valley and The Children’s Medical Center of Dayton.
Dennis A. Lantzy was appointed Senior Vice President, Generation, DPL and DP&L in June 2012. He previously served as Vice President of Generation, DPL and DP&L from February 2012 to June 2012; and Vice President, Engineering and Construction, DPL and DP&L from July 2007 to February 2012. Mr. Lantzy also served as a Business Consultant for the Babcock and Wilcox Company (delivers advanced engineering, manufacturing and construction solutions) from 2004 to 2007 and held various positions during his 31 year career at American Electric Power Company, Inc. (an energy services company) and its affiliates, including Vice President – Environmental Programs and Development Support and Vice President - Generation. He serves as president of the International Power Consulting Company, Inc. Mr. Lantzy joined us in 2007.
Jeffrey K. MacKay was appointed Vice President and Treasurer, DPL and DP&L in July 2012. Mr. MacKay previously served in various project management and financial positions with The AES Corporation, the ultimate parent company of DPL, and its subsidiaries, including Special Project Manager, The AES Corporation from February 2011 to July 2012; Director of Treasury, AES Latin America SRL from March 2008 to February 2011; Financial Manager, AES Panama S.A., from January 2007 to February 2008; and Project Manager, The AES Corporation, from September 2004 to December 2006. Mr. MacKay also worked at Ernst & Young as a regulatory consultant and at Canaccord Adams (formerly Adams Harkness), a boutique investment bank. Mr. MacKay joined us in 2012.
Teresa F. Marrinan was appointed Senior Vice President, Competitive Market Services, DPL and DP&L in January 2012. She previously served as Senior Vice President, Business Planning and Development, DPL and DP&L from September 2010 to December 2011; Senior Vice President, Commercial Operations, DPL and DP&L from February 2010 to September 2010; Vice President, Commercial Operations, DPL and DP&L from August 2007 to February 2010; Managing Director of Portfolio Management, DP&L from April 2007 to August 2007; Director of Portfolio Management, DP&L from September 2006 to April 2007; Head Trader, DP&L from October 2005 to September 2006; and Risk Manager, DP&L from October 1997 to October 2005. In addition, Ms. Marrinan has served in other supervisory positions since joining DP&L in 1984. Ms. Marrinan serves on the Board of the Cox Arboretum Foundation and as Treasurer on the Board of Foodbank.
Bryce W. Nickel was appointed Senior Vice President, Service Operations, DPL and DP&L in June 2012. He previously served as Vice President, Service Operations, DPL and DP&L from February 2010 to June 2012; Vice President, Transmission and Distribution Operations, DP&L from July 2007 to February 2010; and Director, Reliability Operations, DP&L from December 2002 to July 2007. In addition, Mr. Nickel has served in various other supervisory positions with us since joining DP&L in 1981.
Thomas A. Raga was appointed Vice President, External Relations, DPL and DP&L in June 2012. He previously served as Director of Government Relations, DPL and DP&L from December 2010 to June 2012 (overseeing all relationships with governmental entities). Mr. Raga also served as Vice President for Advancement, Sinclair Community College (higher education) from January 2006 to December 2010 (overseeing the working relationships with various organizations external to the college) and as a State Representative, Ohio House of Representatives (state government) from January 2001 to December 2006. Mr. Raga serves on the Board of Directors of the Ohio Electric Utility Institute, the Capitol Square Foundation, the Warren County Foundation, the Warren County Arts & Culture Center and the DP&L Responsible Citizenship Fund. Mr. Raga joined us in 2010.
Timothy G. Rice was appointed Vice President, Acting General Counsel and Corporate Secretary, DPL and DP&L in July 2012. He previously served as Vice President, Assistant General Counsel and Corporate Secretary, DPL and DP&L from January 2008 to July 2012; Interim Senior Vice President, General Counsel and Corporate Secretary, DPL and DP&L from August 2007 to January 2008; and Assistant General Counsel, DPL and DP&L from June 2007 to August 2007, and held various staff attorney positions with DPL and DP&L from March 1985 to June 2007. Mr. Rice serves on the Board of Directors of Daybreak, Inc.; Greater Dayton Volunteer Lawyers’ Project; DP&L Foundation and DP&L Responsible Citizenship Fund. Mr. Rice joined us in 1985.
This Compensation Discussion and Analysis (CD&A) is designed to help you understand how and why the Company compensated the individuals who were named executive officers in fiscal 2011 in the manner it did and to provide context for the detailed compensation tables and narrative descriptions that start on page 121. Throughout this prospectus, the individual who served as our President and Chief Executive Officer (our “CEO”) and the individual who served as our Chief Financial Officer during fiscal year 2011, as well as the other individuals included in the compensation tables, are referred to as the “named executive officers.” The names and positions of our named executive officers for 2011 are set forth in the table below.
On November 28, 2011, we consummated a merger (the “Merger”) with The AES Corporation (“AES”), following which we became a wholly-owned subsidiary of AES. In connection with the Merger, Mr. Stephenson resigned as an executive officer of the Company on December 27, 2011, Messrs. Barbas, Boyle and McCabe resigned as executive officers on December 31, 2011, and Mr. Meyer resigned as an executive officer on June 30, 2012. Mr. Kelly is an executive officer of the Company as of the date of this prospectus.
Name | Position |
Paul M. Barbas | Former President and Chief Executive Officer |
Frederick J. Boyle | Former Senior Vice President and Chief Financial Officer |
Scott J. Kelly | Senior Vice President |
Daniel J. McCabe | Former Senior Vice President and Chief Administrative Officer |
Arthur G. Meyer | Former Senior Vice President and General Counsel |
Gary G. Stephenson | Former Executive Vice President, Operations |
Executive Summary
The following executive summary provides a brief overview of the more detailed disclosures set forth in this Compensation Discussion and Analysis.
Our executive officer pay philosophy was generally to provide competitive market compensation to reward individual and Company short-term and long-term performance and to attract and retain qualified executive officers.
In 2011, we provided our executive officers with base salaries, performance-based annual cash incentives, equity incentives (including performance-based long-term equity incentives), a perquisite allowance, supplemental retirement, deferred compensation opportunities, and severance and change of control benefits. Executive officers were also eligible for other Company benefits generally available to full-time management employees.
The key elements of 2011 named executive officer compensation were (1) base salaries (used to attract and retain), (2) performance-based annual cash incentives based on corporate and individual objectives (used to incentivize short-term performance) and (3) equity awards, including performance-based long-term equity incentives primarily based on the three-year total return that our shareholders received on our stock relative to the stock of other companies (used to incentivize long-term performance).
In 2011, our Board of Directors made all final compensation decisions, based on the recommendations of our Compensation Committee.
The Compensation Committee retained the global compensation consulting firm Towers Watson to help it determine and recommend executive officer compensation. We adopted a Policy on Compensation Consultant Independence in 2009 that required all requests for Towers Watson’s executive compensation services be approved by the Compensation Committee or its Chair.
In the fall of 2010, Towers Watson provided the Compensation Committee with a competitive pay analysis of the compensation established by other companies and their executive officers that were similar to DPL and its executive officers. We reviewed this market data and other factors, such as budgetary considerations, internal pay comparisons and the role of each executive officer, when determining and recommending 2011 executive officer compensation. We considered +/- 15% around the 50th percentile of the market data to be a market competitive range for our executive officers’ target compensation, with the possibility of actual incentive payments above or below that range for superior or diminished performance.
We established target total 2011 compensation (consisting of the key compensation elements of base salaries and target cash and equity incentive payments for annual and long-term performance) for each of the named executive officers within the competitive ranges of the market data we received from Towers Watson.
The 2011 performance goals for named executive officers under our annual cash incentive plan related to achievement in the Company’s net income, the Company’s cash flow from operations, and select individual objectives for each named executive officer. However, with the exception of Mr. Kelly, these goals were not measured for our named executive officers, because their 2011 awards were paid out pursuant to their separation agreements. For a discussion of Mr. Kelly’s award, please see the “Annual Performance-Based Cash Incentives” section of this CD&A.
The performance metric for executive officers under their long-term equity incentive awards granted in 2011 was the Company’s total shareholder return from 2011 to 2013 relative to the total shareholder return of the Company’s strategic peer companies for the same period. Upon consummation of the Merger, the target number of outstanding performance shares vested (on a pro-rated basis, to reflect the shortened performance period) and each vested performance share was converted into a right to receive a cash payment equal to $30.00 (the “Per-Share Merger Consideration”).
Pursuant to a restricted stock matching program that the Company had established for executive officers in 2009 to further align their interests with those of our shareholders, Messrs. Boyle, Kelly and Meyer received shares of restricted stock in 2011 based on their acquisitions of Company common stock in the open market. In 2010, Messrs. McCabe and Stephenson had received the maximum match available under the matching program and were ineligible for more matching restricted stock in 2011. Upon consummation of the Merger, each outstanding share of restricted stock fully vested and was converted into a right to receive the Per-Share Merger Consideration.
We provided a $20,000 cash allowance to each of our named executive officers in 2011 and other limited perquisites. The Compensation Committee did not recommend an annual cash allowance to any executive officer appointed after December 31, 2010.
As in prior years, we made a contribution in 2011 to the account of each named executive officer under a supplemental defined contribution retirement plan that the Company maintains to replace retirement benefits to our executive officers that are lost due to tax regulations that limit their participation in the qualified defined benefit retirement plan that is generally available to all of our employees. Upon consummation of the Merger, our named executive officers received the value of their vested account balances under the plan in the form of a lump sum payment.
In connection with the Merger, Mr. Stephenson resigned as an executive officer of the Company on December 27, 2011 and Messrs. Barbas, Boyle and McCabe resigned as executive officers on December 31, 2011. Each of these named executive officers entered into a separation agreement under which they were entitled to separation payments and benefits from the Company. Mr. Meyer also entered into a separation agreement that entitled him to payments and benefits upon his separation from the Company, which became effective on June 30, 2012. These separation arrangements are more fully described under “Employment Termination and Change of Control Payments.”
Under the oversight of the Company’s Audit Committee, the Company’s Enterprise Risk Management Committee conducted a risk assessment of the Company’s executive officer compensation plans in place during 2011 and found that these plans were not reasonably likely to have a material adverse effect on the Company.
As summarized above, we believe that we established our 2011 executive compensation program within appropriate market competitive and risk parameters and aligned it with the interests of our shareholders by tying the program to the short-term and long-term performance of our Company and ensuring the attraction and retention of qualified executive officers to achieve desired Company performance.
Goals and Objectives of our Standardized Executive Officer Compensation Program
We have a comprehensive standardized compensation program applicable to all executive officers, including the named executive officers. As a former public company, our executive officer compensation program was designed to:
· | Align with our general pay philosophy of providing competitive market compensation to reward individual and Company performance and to attract and retain qualified executives; |
· | Link a significant amount of executive officer compensation to Company annual and long-term performance through incentive plans; and |
· | Provide the Compensation Committee with a logical framework to measure and pay for executive officer performance that is fairly and consistently applied. |
The key elements of our executive compensation program in 2011 were base salaries, performance-based annual cash incentives and equity awards, including performance-based long-term equity incentives. A discussion of the 2011 compensation established under our executive compensation program for each of the named executive officers is located below.
Approach to Executive Officer Compensation
To achieve our compensation goals, we used the 50th percentile of select compensation market data as an initial reference when establishing executive officer: (i) base salaries; (ii) target total cash compensation, which is a combination of base salaries and target cash incentive payments for annual performance; and (iii) target total direct compensation, which is a combination of target total cash compensation and target equity incentive payments for long-term performance.
We used the 50th percentile of select market data to adequately compete with other companies for executive talent and consider +/- 15% around the 50th percentile to be a market competitive range for executive officer base salaries, target total cash compensation and target total direct compensation. We may establish or pay compensation above or below these ranges to recognize budgetary considerations, internal pay equity and individual factors, such as the executive officer’s role, tenure, experience, responsibilities, contributions and potential contributions to the Company and the need for retaining the executive officer in light of the marketplace for his or her experience and skills. In setting 2011 executive officer compensation, we also recognized and reviewed the general economic conditions at the time and its effect on market compensation levels, as well as the restricted stock awards and matching programs that had been granted to the executive officers in prior years.
Our base salaries and non-performance based awards and benefits are primarily designed to attract and retain our executives and our performance-based incentives are primarily designed to link compensation with performance. Our annual cash incentive compensation was intended to reward short-term performance and our equity-based long-term incentive compensation was intended to reward long-term performance. Through this approach, we recognized and balanced an executive’s achievements in managing the day-to-day business and challenges of our Company and the accomplishment of our annual and long-term Company objectives.
Executive Officer Compensation Process
Compensation Committee and Management. In February 2010, the Compensation Committee approved the “DPL Compensation Principles,” a set of compensation principles approved as an amendment to the Compensation Committee Charter. These principles were intended to balance appropriate risk-taking with incenting the right behaviors to drive short- and long-term Company performance. Under the guidance of these “DPL Compensation Principles,” the Compensation Committee oversaw the Company’s executive officer compensation program and plans; approved annual and long-term executive officer goals and objectives; approved and recommended to the Board executive officer base salaries and incentive compensation opportunities; and evaluated the performance of the executive officers in light of previously established goals and objectives. Our CEO recommended to the Compensation Committee base salaries and incentive compensation opportunities for the other executive officers. Our CEO also solicited individual goals from the executive officers, reviewed those goals and then made individual goal recommendations for these executive officers to the Compensation Committee. In 2011, other members of management, consistent with their roles within the Company, also provided information and advice to our CEO and the Compensation Committee on the following matters: the Company’s 2011 operating plan that was used to establish 2011 financial performance goals under our annual incentive plan; peer group, payout schedules and incentive opportunity recommendations for our incentive plans; regulatory developments affecting executive officer compensation; stock ownership guidelines; and risk assessment as it relates to our executive officer compensation program. None of our executive officers, including the CEO, had any direct role in recommending or approving his or her own compensation or award levels and no executive officer was present at any Compensation Committee meeting where his or her performance or compensation was being discussed or determined.
Shareholder Advisory Vote. As a former public company, our Board and the Compensation Committee recognized the significant interests of our shareholders in the compensation practices and policies of our named executive officers. At our 2011 annual meeting, our shareholders approved, on an advisory basis, the 2010 compensation of our named executive officers. Due to the consummation of the Merger, which occurred shortly after our annual meeting, the former Compensation Committee did not have an opportunity to review our compensation program and the results of the advisory vote.
Compensation Consultant. In 2011, the Compensation Committee contracted directly with the global compensation consulting firm Towers Watson under a master services agreement to provide executive compensation related services to it from time to time and had sole authority to approve the fees and the terms of service. The Board of Directors also had separately contracted with Towers Watson under a master services agreement to provide consulting services unrelated to executive officer compensation to the Board or Company management from time to time and the Board had the authority to approve the fees and terms of service.
Under the Company’s policy on compensation consultant independence that was adopted in 2009, executive compensation services requested of Towers Watson by a Compensation Committee member or management had to be approved by the Compensation Committee or its Chair and any other services requested by the Board or management had to be approved by the Board of Directors or its Chairman. In addition, the policy required Towers Watson to provide information to the Compensation Committee concerning all the work it had performed for the Compensation Committee, the full Board of Directors and management. The Compensation Committee also had the right under the compensation consultant independence policy to amend the policy or require Towers Watson to refrain from providing services to the full Board or management, if the Compensation Committee or full Board believed that the services would result in a conflict of interest or influence Towers Watson’s independence or objectivity.
The Compensation Committee engaged Towers Watson to assist it in determining and recommending executive compensation for 2011. Towers Watson provided to the Compensation Committee the following services relating to executive officer compensation: market compensation data and analyses concerning compensation levels; incentive plan design review; executive perquisite analysis; information on current compensation trends; assistance with the Company’s proxy statement; and evaluation of the satisfaction of performance metrics under the Company’s long-term incentive plan and annual performance-based cash incentive plan. The information provided by Towers Watson was given to and used by the Compensation Committee, our CEO and our senior Human Resources executive to assist them in their compensation review, analysis, decisions and recommendations. At the request of the Compensation Committee, Towers Watson attended Compensation Committee and select Board meetings.
Benchmarking. Consistent with its use in prior years, the Compensation Committee used market data provided by Towers Watson in connection with benchmarking and setting 2011 executive officer compensation. The market data included information from energy companies, general industry companies and our strategic peer companies. The Compensation Committee believed that this information would provide a broad and useful set of compensation data to fulfill its goal of attracting and retaining executives from the energy and general industry sectors in which it competes for executive talent. The positions of all of our named executive officers were benchmarked against comparable positions in the energy industry. The positions of Messrs. Barbas, Boyle, Meyer, and McCabe were also benchmarked against comparable positions at our strategic peers. However, Messrs. Kelly and Stephenson’s positions were not benchmarked against comparable positions at our strategic peers because of a lack of market data. With the exception of Mr. Kelly, the positions of each of our named executive officers were also benchmarked against general industry compensation data since those executive officer positions could be recruited more broadly from other industries.
The energy industry and general industry data continued to be based on Towers Watson’s Energy Services Executive Database (the “Energy Benchmarking Survey”) and Towers Watson’s General Industry Executive Compensation Database (the “General Benchmarking Survey”), respectively. Towers Watson reported to us that the Energy Benchmarking Survey database contained the 102 energy companies listed on Annex I of this prospectus and the General Benchmarking Survey included data from the 430 companies listed on Annex II of this prospectus. We had also used these surveys in connection with establishing prior years’ executive officer compensation.
Our strategic peer companies were primarily electric utilities of relatively similar size and strategic positioning to our Company and consisted of the 26 companies listed on page 116 of this prospectus.
Benchmarking data was adjusted by Towers Watson to account for size differences between our Company and the other companies. In addition, to the extent that an executive officer’s additional job functions and responsibilities were not reflected in his or her respective benchmarked job category, the market data could be increased or decreased to account for the additional or reduced responsibilities and job functions in an amount based on Towers Watson’s experience in these matters. The market data for Messrs. Kelly and Stephenson were decreased for 2011 to account for their being only recently promoted to their respective titles or their responsibilities.
For each benchmarked executive officer position, we considered as our initial reference the range between the lowest and highest of the 50th percentiles of the strategic peer group, energy industry, and general industry market data. This range was used to help ensure that our executive officer compensation was competitive and appropriate relative to our strategic peer companies, as well as to the broader group of energy and general industry companies in which our executive officers could potentially seek employment. We considered +/- 15% around this range (the “Target Competitive Range”) to be a market competitive range for executive officer base salaries, target total cash compensation and target total direct compensation. The setting of our named executive officer base salaries; annual incentive opportunities and resulting target total cash compensation; and long-term incentive opportunities and resulting target total direct compensation is discussed further below.
Impact of Tax and Accounting Requirements. As a former public company, Section 162(m) of the Internal Revenue Code generally limited the Company’s income tax deduction for compensation paid to certain of its executive officers to $1 million, unless the compensation was based upon certain performance objectives or otherwise excluded from the limitation, such as is the case with our long-term incentive performance share awards. We undertook to qualify certain components of our incentive compensation to executive officers for the performance exception to non-deductibility. However, the Company could choose to forego the deductions on occasion if it determined such action to be in the best interests of the Company to recognize and motivate executive officers as circumstances warranted. In addition, when determining whether to offer a particular form of equity compensation to executives, the Compensation Committee took into account the accounting implications associated with that form of compensation.
Stock Ownership Guidelines. As a former public company, the Company had stock ownership guidelines for officers to help align the interests of our executive officers and shareholders. Company securities that qualified for the guidelines included earned performance shares, restricted stock, common shares (including those held in our former employee stock ownership plan and the 401(k) plan) and any of the foregoing that were deferred by the
officer under a Company plan. Officers were required to maintain ownership of Company securities in accordance with the guidelines set forth below.
Position | Ownership as a Multiple of Base Salary | |||
Chief Executive Officer | 5.5 | X | ||
Executive Vice President or Senior Vice President | 2 | X | ||
Vice President | 1 | X |
Each officer was required to retain at least 50% of any after-tax shares he or she received from restricted stock awards or under our long-term incentive plan until the officer satisfied these stock ownership guidelines. If approved by our CEO and senior Human Resources executive, an officer could be excused from these guidelines if he or she was under a hardship situation or was within three years of retiring from the Company. No requests for, or approvals of, any excusals were made under our stock ownership guidelines. Given the short tenure of many of the Company’s executives, the Company’s Board of Directors anticipated a period of several years before executives would meet the guidelines. As such, the terms of the stock ownership guidelines did not include any repercussions for not complying with the guidelines. Immediately prior to the consummation of the Merger, Mr. Barbas, who had been our President and Chief Executive Officer for less than six years, had acquired approximately 69.75% of the stock necessary to satisfy his stock ownership guideline and the other named executive officers had fully satisfied their guidelines that had been in place for them since 2007. The average stock price of Company common stock during the 12 months prior to the Merger was used to determine satisfaction of the guidelines.
Executive Compensation Program Elements
Our executive compensation program is designed to create a balance between fixed and variable pay, short-term and long-term compensation and cash and equity-based compensation. We do not target an element or form of compensation to be a particular percentage of total compensation. As a former public company, the Compensation Committee reviewed the weighting of each element of compensation in the context of the market data, budgetary considerations, internal pay equity and each executive officer’s individual factors to ensure that such weightings conformed to our compensation goals and our philosophy of linking a significant portion of an executive’s pay to performance and attracting and retaining qualified executives. Weightings among executive officers varied depending on these factors.
The key elements of compensation provided to our named executive offices in 2011 were:
· | Base salaries; |
· | Opportunities to earn annual performance-based cash incentives under our Executive Incentive Compensation Plan; and |
· | Opportunities to earn long-term performance-based equity incentives and other equity awards under our Equity Performance and Incentive Plan. |
In connection with the Merger, we also provided payments and benefits under our Severance Pay and Change of Control Plan and/or individual separation agreements to certain of our executive officers.
The Company also provided its executive officers with an Executive Cash Perquisite Allowance and other limited perquisites, a Supplemental Executive Defined Contribution Retirement Plan, a Pension Restoration Plan, Executive Deferred Compensation Plans and, for Mr. Meyer, a Supplemental Executive Retirement Plan and Executive Healthcare Plan. Named executive officers were also eligible for Company benefits that were generally available to all full-time management employees of the Company, including The Dayton Power and Light Company Employee Savings Plan (a 401(k) plan which formerly included Company matching contributions of Company common stock); the former DPL Inc. Employee Stock Ownership Plan; The Dayton Power and Light Company Retirement Income Plan; charitable contribution matching program; health, dental and vision coverage; Company-paid life insurance; disability insurance; tuition reimbursement; paid holidays, vacation and illness time; and other benefits. Company shares in participant accounts under The Dayton Power and Light Company Employee Savings
Plan and the former DPL Inc. Employee Stock Ownership Plan were cashed out in connection with the Merger and the proceeds from such shares were rolled into The Dayton Power and Light Company Employee Savings Plan.
Base Salaries
Base salaries are designed to attract and retain experienced and qualified executives and to provide executives with fixed cash compensation for services rendered during the year. While we were a public company, the Compensation Committee typically approved base salary rate adjustments at its February meeting and periodically at times throughout the year to reflect changes in job scope or responsibility.
The 2011 base salary rates for the named executive officers were set in February 2011 after reviewing the compensation market data from Towers Watson and our CEO’s base salary recommendations for executive officers other than himself. The base salary rates were established after consideration of the market data for the executive officers’ respective job functions, budgetary considerations, internal pay comparisons and the executive officers’ prior compensation levels, experience in their respective fields and with our Company, past and potential contributions, demand for skill sets in the marketplace and our desire to retain these individuals. The 2011 base salary rates for the named executive officers were set within the Target Competitive Ranges for the named executive officers’ respective benchmarked positions.
The following table shows for each named executive officer the annual base salary rate that took effect in February 2011, the annual base salary rate that was in effect immediately prior to February 2011 and the percentage increase between those two annual base salary rates. The actual base salary amounts paid to the named executive officers for 2011 are set forth under the “Salary” column of the Summary Compensation Table on page 121.
Annual Base Salary Rates
Name | 2010 Annual Base Salary Rate | 2011 Annual Base Salary Rate | Percentage Increase | |||||||||
Mr. Barbas | $ | 675,000 | $ | 720,000 | 6.7 | % | ||||||
Mr. Boyle | $ | 350,000 | $ | 390,000 | 11.4 | %* | ||||||
Mr. Kelly | $ | 280,000 | $ | 290,000 | 3.6 | % | ||||||
Mr. McCabe | $ | 293,000 | $ | 320,000 | 9.2 | % | ||||||
Mr. Meyer | $ | 286,200 | $ | 325,000 | 13.6 | %** | ||||||
Mr. Stephenson | $ | 365,000 | $ | 400,000 | 9.6 | % |
* | Mr. Boyle’s 2011 annual base salary rate and percentage increase reflect, in part, the expansion of his responsibilities to include corporate development. |
** | Mr. Meyer’s 2011 annual base salary rate and percentage increase, reflect, in part, his assuming the role of general counsel and the consequent expansion of his duties and responsibilities. |
Annual Performance-Based Cash Incentives
Overview. All of our named executive officers participated in our Executive Incentive Compensation Plan (“EICP”) for 2011. The EICP was an annual performance-based cash incentive plan that rewarded achievement of annual corporate and individual performance goals. The EICP was designed to recognize and reward the contributions of individual executives as well as the contributions of the executive officer group to overall corporate success. The Compensation Committee believed that this type of annual cash incentive plan helped achieve our short-term Company objectives by focusing our officers on short-term performance targets that impact Company performance and shareholder return. The Compensation Committee established our CEO’s target annual incentive opportunity and performance goals under the EICP and, after reviewing our CEO’s recommendations, also approved and adopted annual incentive opportunities and performance goals for the other named executive officers.
The Compensation Committee’s intent was that these EICP performance goals should require strong performance levels relative to current business conditions, with actual performance either exceeding or falling below target performance in any given year. Maximum performance levels should be achieved only if performance results were exceptional. Performance results were required to achieve threshold performance for any payout to occur.
Target payouts under the EICP were doubled for performance at the maximum level and reduced in half for performance at threshold, with an opportunity to receive a payout if performance was in between set levels of performance. However, no payouts under the EICP could have been made for any year in which the Company had reduced the dividend on its common stock.
Target Annual Incentive Opportunities. Target annual incentive opportunities under the EICP were set annually as a percentage of base salary after reviewing the target total cash compensation market data provided by Towers Watson, budgetary considerations, internal pay comparisons and the executive officers’ prior compensation levels, experience in their respective fields and with our Company, past and potential contributions, demand for skill sets in the marketplace and our desire to retain these individuals. Target total cash compensation was a combination of base salary and target annual incentive cash compensation under the EICP, and represented the target amount of compensation in the form of cash for day-to-day duties and annual performance that the Compensation Committee believed was appropriate to meet the Company’s compensation goals when determining executive officer compensation for the year.
The 2011 target total cash compensation for the named executive officers was set within the Target Competitive Ranges for their respective benchmarked job positions. The resulting 2011 target annual incentive opportunities (expressed as a percentage of base salary) for the named executive officers that were approved by the Compensation Committee at its February 2011 meeting are set forth in the table below.
Name | 2011 Target EICP Opportunity (% of base salary) | |
Mr. Barbas | 75% | |
Mr. Boyle | 50% | |
Mr. Kelly | 45% | |
Mr. McCabe | 50% | |
Mr. Meyer | 50% | |
Mr. Stephenson | 60% |
Overview of Performance Goals. Performance goals under the EICP varied annually to reflect the Company’s business plans and market conditions. The 2011 EICP performance goals established by our Compensation Committee for the named executive officers related to (i) the corporate financial measures of diluted earnings per share (EPS) and cash flow from operations (CFFO) and (ii) individual, operational and strategic tasks specific to each executive officer’s responsibilities. As discussed below, the EPS performance goal was replaced with a net income performance goal following the consummation of the Merger with AES. The weighting among the EICP performance goals for each of the named executive officers was as follows:
Name | Net Income | CFFO | Individual Goals | |||
Mr. Barbas | 55% | 15% | 30% | |||
Mr. Boyle | 55% | 15% | 30% | |||
Mr. Kelly | 45% | 5% | 50% | |||
Mr. McCabe | 55% | 15% | 30% | |||
Mr. Meyer | 55% | 15% | 30% | |||
Mr. Stephenson | 50% | 15% | 35% |
The performance goal weightings reflected the continued emphasis on corporate financial goals that align an executive officer’s performance in relevant areas of responsibility and influence with overall Company performance and executive team-building. Mr. Kelly’s performance goals were more heavily weighted in the area of individual performance to reflect his focus on improving the operations of one of our Company’s subsidiaries. The Compensation Committee believed that the weightings of the EICP performance goals for our CEO and other named executive officers would emphasize the Company’s objective of overall Company performance and at the same time continue to recognize and reward strong performance for individual objectives.
2011 EICP goals and objectives were established at the Compensation Committee’s February meeting. Initial performance measures for the EICP goals were also established at the Compensation Committee’s February meeting based, in part, on the Company’s operating plan for the year at that time. In April 2011, the performance measures
for Messrs. Stephenson and McCabe were revised, in the case of Mr. Stephenson, to reflect his role with respect to power generation, and, in the case of Mr. McCabe, to account for additional responsibilities that he assumed in the information technology area.
Corporate Financial Goals. As noted above, EICP corporate financial goals initially established for 2011 related to diluted earnings per share (EPS) and cash flow from operations (CFFO). EPS is an indicator of a company’s net income and profitability from operations and CFFO is an indicator of how effectively a company generates cash from its operations. The Compensation Committee recommended the continued use of diluted earnings per share as a corporate financial goal for 2011 because it believed that investors are focused on earnings per share when measuring Company performance and profitability and thus an EPS goal would align the interests of management with our investors. The Compensation Committee also recommended the continued use of the CFFO corporate financial goal because liquidity is also important for our Company and of interest to our investors, and the use of the CFFO corporate financial measure was designed to emphasize and align management goals with those liquidity interests. In sum, the Compensation Committee believed that strong EPS and CFFO performance were important measures to gauge overall Company performance and to align named executive officer financial goals with shareholder interests in corporate profitability and liquidity. The EPS and CFFO performance measures were adjusted during 2011 to reflect a budgeting correction related to the rate applicable to the amount of fuel costs that DP&L is entitled to recover pursuant to its PUCO-approved fuel and purchased power recovery rider.
Following the consummation of the Merger, the EPS measure was replaced by a net income measure in light of all outstanding shares of the Company being acquired by AES in the Merger. The net income performance measures were based on the net income amounts that had been used to establish the EPS performance measures. Like EPS, net income is an indicator of a company’s profitability from operations, and we believed that the net income measure would offer and reflect the same incentives for performance as the EPS measure. For purposes of measuring performance of the net income and CFFO goals under the EICP, the actual results of net income and CFFO were adjusted to account for certain events that occurred during the year that the Company believed obscured its performance in 2011. Net income was adjusted to account for Merger related expenses, including those related to changes in interest expense and debt costs as well as purchase accounting expenses; unrealized gains and losses from gross margin derivative activity; severe storm costs; and certain tax charges. CFFO also was adjusted to account for Merger related expenses, including those related to changes in interest expense and debt costs, purchase accounting expenses and the liquidation of DPL stock in master trusts; and severe storm costs.
The Company’s actual 2011 unadjusted net income and unadjusted CFFO are included in the 2011 audited financial statements of the Company filed with the SEC as part of the Company’s Annual Report on Form 10-K/A for fiscal year ended December 31, 2011. The Company’s unadjusted net income and unadjusted CFFO for 2011 are labeled in our 2011 audited financial statements, respectively, as “Net income (loss)” in the Company’s Consolidated Statements of Results of Operations and as “Net cash provided by (used for) operating activities” in the Company’s Consolidated Statements of Cash Flows.
The following table shows the 2011 EICP corporate financial goals and the performance measures (as adjusted) used to measure these goals and our year-end results for adjusted net income and adjusted CFFO. Please note the performance measures and results for the corporate financial goals are provided in the limited context of the Company’s 2011 compensation program and should not be understood to be a statement of the Company’s actual 2011 results as reported in its audited financial statements or the Company’s expectations or estimates of results of operations or compensation goals for 2012 or any other year.
Corporate Financial Goals - 2011
Corporate Financial Goal | Threshold | Target | Maximum | Adjusted Results | ||||||||||||
Diluted Earnings Per Share (EPS) | $ | 2.06 | $ | 2.22 | $ | 2.37 | N/A | |||||||||
Net Income ($ in millions) | $ | 235.7 | $ | 253.4 | $ | 271.1 | $ | 238.4 | ||||||||
Cash Flow From Operations (CFFO) ($ in millions) | $ | 366.8 | $ | 407.6 | $ | 448.4 | $ | 368.2 |
CEO Individual Goals. Individual goals for our CEO were determined by the Compensation Committee after consultation with our CEO. For 2011, our CEO’s individual goals consisted of three strategic tasks that the Compensation Committee determined were important for our CEO to achieve in 2011. These goals related to the Company’s (i) progress towards strategic expansion or repositioning of the Company, (ii) safety program design and targets and (iii) developing a plan for the accomplishment of certain regulatory activities.
Individual Goals for Other NEOs. The Compensation Committee believed that the CEO was in the best position to recommend executive officer individual goals that align with the strategic and functional responsibilities of these officers. Annually, each executive officer (other than the CEO) submits his or her proposed goals to our CEO for his review. Our CEO reviews these goals and, while we were a public company, submitted individual goals for these executive officers to the Compensation Committee for its approval. For 2011, the individual goals recommended by our CEO were approved by the Compensation Committee and consisted of strategic and operational tasks related to the named executive officers’ business areas. Our CEO and the Compensation Committee believed that these goals were important for 2011 Company performance and also for positioning the Company in 2011 for strong performance in future years.
Mr. Boyle had three strategic goals relating to the Company’s (i) safety program design and targets, (ii) strategic expansion or repositioning and (iii) 2012 regulatory activities, including certain rate-related filings.
Mr. Kelly had four strategic goals relating to his business unit’s (i) achievement of retail budget targets, (ii) customer retention, (iii) customer satisfaction and (iv) systems implementation.
Mr. McCabe had four strategic goals relating to the Company’s (i) regulatory compliance, (ii) safety program design and targets, (iii) labor strategy and negotiation, and (iv) strengthening information technology leadership processes.
Mr. Meyer had three strategic goals relating to the Company’s (i) customer satisfaction, (ii) 2012 regulatory activities, including certain rate-related filings and (iii) safety program design and targets.
Mr. Stephenson had five strategic goals relating to his business unit’s (i) achievement of retail budget targets, (ii) customer satisfaction targets, (iii) safety program design and targets, (iv) achievement of equivalent forced outage rate (“EFOR”) targets, and (v) achievement of equivalent availability (“EA”) targets. EFOR is a measure of how often unscheduled plant shutdowns occur and EA is a measure of the power available for consumption.
2011 Award Determinations. After the end of each fiscal year, an executive officer’s initial EICP value is calculated based on the performance of all of the officer’s EICP goals for the previous year. The Compensation Committee then assigns each executive officer an individual contribution factor of between 0.5 and 1.5, which is used as a multiplier to reduce, maintain or increase the initial EICP value based on the performance of the officer. Use of individual contribution factors allows the Compensation Committee, in part, to recognize outstanding individual performance and the manner in which goals are accomplished (e.g., promotion of teamwork, reflecting our corporate values, level of risk incurred by the Company).
With the exception of Mr. Kelly, these goals were not measured for our named executive officers, because their 2011 awards were paid out pursuant to their separation agreements, as described below under “Employment Termination and Change of Control Payments” starting on page 133. At the completion of 2011, Mr. Kelly was eligible to receive a 2011 EICP award of $112,151, since he had successfully completed 85.9% of his 2011 EICP goals and objectives. However, Mr. Kelly’s award was modified so that his cash bonus percentage was substantially equal to the median cash bonus percentage of all management employees during 2011. This modification reduced his cash bonus under the EICP from $112,151 to $75,141 (or 57.6% of his target EICP award for 2011). This amount is included under the “Non-Equity Incentive Plan Compensation” column of the Summary Compensation Table on page 121.
Equity Compensation under the Equity and Performance Incentive Plan
Overview. The Company’s Equity and Performance Incentive Plan (“EPIP”) authorizes various types of awards, including performance shares, restricted stock, common stock, stock options and cash. Only performance
shares and restricted stock were awarded to executive officers under the EPIP and no other forms of compensation, including common stock, stock options or cash, were awarded under the EPIP to executive officers during 2011. The Compensation Committee provided opportunities to earn long-term incentive compensation under the EPIP to align executives’ interests with the interests of our shareholders, to promote teamwork among the participants toward accomplishment of long-term Company goals and to attract and retain executives by allowing them to share in the Company’s success.
Long-Term Performance-Based Incentives. In 2011, we used our Long-Term Incentive Plan (the “LTIP”) developed under the EPIP to motivate and reward executive officers for long-term Company performance, to provide an opportunity for executive officers to increase stock ownership in the Company and to help retain our executive officers. The Board granted the long-term incentive awards 1/3 in restricted stock and 2/3 in performance share awards that could be earned at the end of a three-year period if performance conditions were met. The restricted shares were granted for retention purposes and would have cliff-vested at the end of the three year performance period. The Compensation Committee believed that awards under the LTIP provided a clear link to the long-term interests of shareholders because 2/3 of the awards were paid only if the Company realized superior total shareholder return relative to comparable energy companies over a multi-year period and the ultimate value of the award was tied to the Company’s stock price. The multi-year performance time period and multi-year vesting period also created overlapping award cycles that served as an effective retention device. We applied a change of control vesting feature to our LTIP performance share and restricted share awards to provide executive officers the same opportunities as our other shareholders who would be free to realize the value created at the time of a change of control transaction by selling their stock, pro-rated to reflect the executive officer’s performance through the date of the change of control in the case of performance shares. Upon consummation of the Merger, the target number of outstanding performance shares vested, on a pro-rated basis to reflect the shortened performance period, and such shares were converted into the right to receive the Per-Share Merger Consideration. Restricted shares vested and were also converted into the right to receive the Per-Share Merger Consideration.
LTIP performance share awards were based on the Company’s total shareholder return relative to a composite of energy industry peers over a three-year period. Total shareholder return is determined by measuring the appreciation of the Company’s share price over a three-year period, adding the value of dividends declared and paid over that time period and then dividing that amount by the Company’s share price at the beginning of the time period. Total shareholder return relative to our peers was used because the Compensation Committee believed that it effectively measured the benefit that the Company’s shareholders realized on their investment in our common stock compared to investment opportunities in other similar companies and provided an effective link between pay and long-term performance. The LTIP program was intended to motivate the executive officer to increase total shareholder return to enhance his or her overall compensation under the program. Not only was the LTIP earned in shares of Company common stock, but an executive officer would have earned more common shares as our total shareholder return increased compared to our peers. As a result, the Compensation Committee believed that the LTIP effectively aligned the executive officers’ interests with those of our shareholders.
A new three-year LTIP cycle would begin each year and at the end of the three-year cycle, the Company’s total shareholder return was compared with a group of peer companies to determine the number of shares earned relative to a predetermined payout schedule. The Compensation Committee periodically evaluated the companies included in our strategic peer group to determine appropriate long-term performance comparisons. For LTIP cycles commencing with the 2008-2010 cycle, including the 2011-2013 LTIP cycle award granted in 2011, companies in our Strategic Peer Group were used for comparison purposes. The companies in our Strategic Peer Group were primarily electric utilities of relatively similar size and similar strategic positioning to our Company, and were companies that the Company competed with in the capital markets. When it established the 2011-2013 LTIP cycle, the Compensation Committee believed that comparison to the companies in our Strategic Peer Group would provide an appropriate indicator of the relative long-term performance of the Company.
The table below sets forth the Strategic Peer Group companies for the 2011-2013 LTIP cycle.
Strategic Peer Group
Alliant Energy Corporation | Entergy Corporation | NV Energy, Inc. | Public Service Enterprise Group, Inc. |
Calpine | FirstEnergy Corp. | OGE Energy Corporation | RRI Energy |
CMS Energy Corporation | Great Plains Energy, Inc. | Pepco Holdings, Inc. | Westar Energy Inc. |
Consolidated Edison | Hawaiian Electric Industries, Inc. | Pinnacle West Capital | Wisconsin Energy Corporation |
DTE Energy Company | Northeast Utilities | PNM Resources, Inc. | Xcel Energy |
Dynegy | NRG Energy | Portland General Electric Company | |
Edison International | NSTAR | PPL Corporation |
For an executive officer to receive any performance shares, our total shareholder return for the cycle must have placed the Company at or above the 30th percentile of the LTIP comparator group of companies. LTIP participants would have been entitled to receive a portion of their target performance shares between set levels of performance above the 30th percentile.
The table below sets forth the LTIP Payout Schedule that had been established by the Compensation Committee for the 2011-2013 LTIP cycle.
2011-2013 LTIP Payout Schedule
Percentile Rank Versus Peers | % of Target Shares Earned | ||
90th percentile | 200% | ||
75th percentile | 150% | ||
50th percentile | 100% | ||
40th percentile | 50% | ||
30th percentile | 25% | ||
Below 30th percentile | 0% |
Each participating executive officer was generally awarded a target LTIP opportunity as a percentage of his or her base salary for a new LTIP cycle established each year. Executive officers’ LTIP opportunities were multiplied by their annual base salary rates to establish target LTIP values. To calculate the number of target performance shares that could be earned at the end of the 2011-2013 LTIP cycle, the target LTIP values for the 2011-2013 LTIP cycle were divided by the average closing market price of the Company’s shares of common stock over the 30-day period preceding the award date of February 22, 2011. As noted above, upon consummation of the Merger, all outstanding performance shares and restricted shares vested (pro-rata and fully, respectively) and were converted into the right to receive the Per-Share Merger Consideration.
In connection with establishing 2011 target long-term incentive opportunities for executive officers, the Compensation Committee reviewed the market data provided by Towers Watson for target total direct compensation. Target total direct compensation is a combination of base salary, target annual incentive cash compensation under our EICP and target long-term incentive equity compensation under the LTIP, and represents the target amount of total direct compensation for a named executive officer that the Compensation Committee believed was appropriate to meet the Company’s compensation goals when determining executive officer compensation for the year.
The 2011 target total direct compensation for all the named executive officers was set within the Target Competitive Ranges for their respective benchmarked job positions.
The resulting 2011-2013 LTIP target incentive opportunities (expressed as a percentage of base salary) for the named executive officers that were approved by the Compensation Committee at its February 2011 meeting are set forth in the table below.
Name | Target 2011-2013 LTIP Opportunity (% of base salary) | ||
Mr. Barbas | 150% | ||
Mr. Boyle | 100% | ||
Mr. Kelly | 75% | ||
Mr. McCabe | 85% | ||
Mr. Meyer | 85% | ||
Mr. Stephenson | 100% |
The grant date fair values of the 2011-2013 LTIP cycle awards granted in 2011 are included in the amounts reflected in the “Stock Awards” column for 2011 in the Summary Compensation Table on page 121.
Other Stock Awards. The Board granted shares of Company restricted stock (“Match Shares”) to the named executive officers, other than Mr. Barbas, pursuant to a restricted stock matching program established for them in 2009. Under the program, the Company agreed to match shares of Company common stock acquired in the open market by the executive officer for a three-year period ending September 17, 2012 (the “Match Period”) with shares of Company restricted stock based upon the value of all Company common shares purchased by the executive officer during the Match Period. The match percentage varied based upon the total value of stock purchased as a percentage of the executive officer’s 2009 base salary. In 2010, Messrs. McCabe and Stephenson had reached the maximum match attainable based upon their respective 2009 base salary. Thus, they received no matching restricted shares in 2011. The table set forth below shows for each named executive officer the number of Match Shares granted for 2011.
Name | # of Match Shares Granted in 2011 | ||
Mr. Boyle | 47 | ||
Mr. Kelly | 8,673 | ||
Mr. McCabe | 0 | ||
Mr. Meyer | 51 | ||
Mr. Stephenson | 0 |
The restricted stock matching program established by the Compensation Committee is discussed further in the narrative following the Grants of Plan-Based Awards—2011 table on page 124.
In addition, Mr. Boyle was awarded 10,000 shares of restricted stock in light of his assumption of corporate development responsibilities, in recognition of his overall accomplishments and for retention purposes.
Upon consummation of the Merger, each outstanding share of restricted stock fully vested and was converted into the right to receive the Per-Share Merger Consideration. We applied a change of control vesting feature to provide executive officers the same opportunities as our other shareholders who would be free to realize the value created at the time of a change of control transaction by selling their stock.
The grant date fair values of the stock awards granted to the named executive officers for 2011 are included under the “Stock Awards” column of the Summary Compensation Table on page 121.
Severance Pay and Change of Control Plan
Under our Severance Pay and Change of Control Plan, we provide benefits to certain executive officers, including the named executive officers, if their employment is terminated under certain circumstances, including after a change of control of the Company. Prior to the adoption of this plan, the manner in which each executive officer would be compensated either as a result of a voluntary or involuntary termination or upon a change of control varied and was based on negotiated terms in individual employment agreements and change of control agreements.
We believe it is important to provide severance payments to bring certainty and clarity when a separation from service occurs. In addition, because executive officers are vulnerable to discharge upon a change of control, a provision in the Severance Pay and Change of Control Plan covering a change of control helps to ensure continued employment and dedication of our executive officers despite the concerns they may have regarding their own continued employment before or after a change of control. To reduce these concerns, the plan offers executive officers certain market competitive multiples of compensation and benefits in the event of termination in the context of a change of control.
The Company’s severance and change of control arrangements are established separately from, and do not affect, our other compensation elements. We seek to offer severance and change of control benefits and terms that are reasonable and appropriate relative to the marketplace and that accomplish our purposes discussed above. Among the benefits offered, we provide conditional tax gross-up payments for taxes incurred by executive officers on their change of control payments and benefits if such payments and benefits are more than 110% of the safe harbor amount that would not subject the payments and benefits to these taxes. Based on market and good corporate governance practices, the Board determined in 2009 that any new participant in the Severance Pay and Change of Control Plan on or after January 1, 2010 would not be entitled to tax gross-up benefits provided under the plan.
Additional information about the Severance Pay and Change of Control Plan and the separation agreements that we entered into with each of Messrs. Barbas, Boyle, McCabe, Meyer and Stephenson is located starting on page 133.
Perquisites and Other Compensation and Related Plans
Perquisites. For attraction and retention purposes, the Company provided executive officers appointed before January 1, 2011 with an annual cash perquisite allowance of $20,000. An executive officer may use the cash perquisite allowance to purchase the perquisites that he or she desires, such as financial planning, additional life insurance or disability benefits. The Compensation Committee believed that the cash perquisite allowance and other limited perquisites the Company paid in 2011 were reasonable for its compensation purposes.
Supplemental Executive Defined Contribution Retirement Plan. We maintain a Supplemental Executive Defined Contribution Retirement Plan (“SEDCRP”) to replace retirement benefits to our executive officers that are lost due to tax regulations which limit executive officer participation in our qualified defined benefit retirement plan (“DP&L Retirement Income Plan”) available to all employees. In connection with the consummation of the Merger, participants’ unvested Company contributions were vested and account balances were distributed in a lump sum. A description of the SEDCRP is in the narrative following the “Nonqualified Deferred Compensation – 2011” table located on page 127 of this prospectus.
Pension Restoration Plan. The Company maintains a Pension Restoration Plan that restores benefits under the DP&L Retirement Income Plan to an executive officer that are lost due to the executive officer’s election to defer base salary into the Company’s deferred compensation plans. The Pension Restoration Plan was adopted to provide make-up benefits to executive officers who otherwise would have received a reduced benefit from the DP&L Retirement Income Plan. Although each executive officer of the Company was entitled to participate in the Pension Restoration Plan, no officer actively participated during 2011.
Deferred Compensation Plans for Executive Officers. In 2011, the Company maintained plans to allow its executive officers, including the named executive officers, to defer the receipt of all or a portion of their earned pre-tax base salaries and incentive compensation payments. We believe that providing these types of plans is an important recruitment and retention tool that can be provided by the Company at a relatively low cost. These obligations are provided for through a master trust as a result of the consummation of the Merger. A description of our deferred compensation plans for executive officers is in the narrative following the “Nonqualified Deferred Compensation - 2011” table located on page 127 of this prospectus.
Risk Assessment of Executive Officer Compensation Program
Our Audit Committee was responsible for assessing risks associated with the Company’s executive compensation program and reporting its assessment to the Compensation Committee. The Compensation
Committee reviewed the Audit Committee’s risk assessment results in connection with its recommendations to the full Board on executive officer compensation. At the request of the Audit Committee, Company management reviewed our executive officer compensation program to assess the program’s potential risks to the Company. After reviewing management’s findings, the Audit Committee concluded that it did not believe that the Company’s 2011 executive officer compensation program encouraged our named executive officers to take excessive or unnecessary risks. The Compensation Committee reviewed the findings of Company management and the conclusions of the Audit Committee. Among other factors:
· | We believed that our 2011 executive officer compensation program contained an appropriate balance between fixed and incentive-based pay, and between short-term and long-term pay, that was consistent with industry practice, and that the 2011 base salary amounts established for the Company’s named executive officers were a sufficient component of total direct compensation to help discourage unnecessary risk-taking. |
· | Financial performance goals for 2011 under our EICP (our annual cash incentive plan) were based on the Company’s operational plan that was reviewed and approved by the Board. We believed that these goals were attainable without the need to take unnecessary or inappropriate risks. Short-term performance goals for 2011 included a mix, weighting and sharing of financial and individual objectives among executives which helped to ensure that one objective did not overly influence or create undue short-term incentives for the executive officers and that we believed correlated to the creation of shareholder value. Assuming achievement of at least a minimum level of performance, payouts under the EICP resulted in some compensation at levels below full target performance (rather than an all-or-nothing approach). Payouts were also capped at 200% of target to protect against excessively large short-term incentives. The Compensation Committee also had discretion under our annual cash incentive plan, through the use of a multiplier, to modify the size of any award based on those factors it deemed appropriate, such as whether an executive has caused the Company to incur unnecessary or excessive risk. |
· | Our executive compensation program contained a significant amount of long-term, equity-based incentives in the form of performance shares and restricted stock with one or more time-based and performance-based conditions that focus our executive officers on ensuring the long-term viability and success of the Company. Three-year performance share grants were made annually, which resulted in executive officers always having unvested long-term stock awards that could decrease significantly in value if our business was not managed for the long term and overlapping performance periods so any risks taken to increase payout under one award could jeopardize potential payouts under other awards. Assuming achievement of at least a minimum level of performance, payouts under our long-term incentive plan resulted in some performance share awards at levels below full target performance (rather than an all-or-nothing approach). Payouts were also capped at 200% of target to protect against excessively large payouts. |
· | In 2011, we had executive officer stock ownership guidelines in place to ensure that each executive had a significant amount of personal wealth tied to the performance of our stock. In addition, executive officers were required to retain at least 50% of any after-tax performance shares and restricted stock until the stock ownership guidelines were met. |
RISK ASSESSMENT OF MANAGEMENT AND EMPLOYEE COMPENSATION PROGRAMS
In addition to the risk assessment of the Company’s executive officer compensation program described in the preceding Compensation Discussion and Analysis section of this prospectus, the Company’s Enterprise Risk Management Committee also reviewed the Company’s 2011 management and employee compensation programs to assess the programs’ risks, and reported its findings and conclusions to the Company’s Audit Committee.
The Enterprise Risk Management Committee developed a risk assessment process for its review of 2011 management and employee compensation programs, which included:
· | Identifying features of plans and programs that could induce management and other employees to take risks that are reasonably likely to have a material adverse effect on the Company; |
· | Establishing appropriate standards of materiality; |
· | Identifying short-term and long-term risks facing the Company; |
· | Identifying management and other employee compensation plans and programs that do not pose a material risk to the Company; and |
· | Identifying mitigating factors that limit risks of certain compensation plans. |
After assessing the risk of the Company’s management and employee compensation programs within the risk assessment framework described above, the Enterprise Risk Management Committee concluded that the 2011 management and employee compensation plans did not create risks that are reasonably likely to have a material adverse effect on the Company. These findings were based on the overall alignment of shareholder interests with the plans, risk mitigation features included in the plans and the absence of other features that could induce unreasonable risk. The Audit Committee reviewed and adopted the Enterprise Risk Management Committee’s risk assessment conclusions with respect to the 2011 management and employee compensation plans.
EXECUTIVE COMPENSATION
Set forth below is certain information concerning the compensation of our named executive officers. Compensation information for each named executive officer is given for the earliest of the last three completed years that the officer was a named executive officer of the Company and all subsequent completed years.
Summary Compensation Table
Name and Principal Position | Year | Salary | Bonus (1) | Stock Awards (2) | Non-Equity Incentive Plan Compensation (3) | Change in Pension Value and Nonqualified Deferred Compensation Earnings (4) | All Other Compensation (5) | Total | ||||||||||||||||||||||
Paul M. Barbas Former President & CEO | 2011 | $ | 712,039 | $ | 0 | $ | 1,083,675 | $ | 0 | $ | 18,242 | $ | 7,333,714 | $ | 9,147,670 | |||||||||||||||
2010 | $ | 675,000 | $ | 0 | $ | 949,269 | $ | 668,024 | $ | 39,472 | $ | 250,281 | $ | 2,582,046 | ||||||||||||||||
2009 | $ | 683,654 | $ | 0 | $ | 1,174,913 | $ | 447,633 | $ | 30,407 | $ | 216,000 | $ | 2,552,607 | ||||||||||||||||
Frederick J. Boyle Former SVP & Chief Financial Officer | 2011 | $ | 382,923 | $ | 0 | $ | 653,324 | $ | 0 | $ | 14,394 | $ | 2,403,692 | $ | 3,454,333 | |||||||||||||||
2010 | $ | 346,923 | $ | 0 | $ | 484,606 | $ | 233,969 | $ | 42,114 | $ | 113,981 | $ | 1,221,593 | ||||||||||||||||
2009 | $ | 330,192 | $ | 0 | $ | 1,162,959 | $ | 154,252 | $ | 32,988 | $ | 65,833 | $ | 1,746,224 | ||||||||||||||||
Scott J. Kelly SVP | 2011 | $ | 288,231 | $ | 0 | $ | 455,971 | $ | 75,141 | $ | 90,976 | $ | 85,969 | $ | 996,288 | |||||||||||||||
2010 | $ | 278,154 | $ | 31,416 | $ | 264,970 | $ | 125,663 | $ | 67,211 | $ | 79,411 | $ | 846,825 | ||||||||||||||||
Daniel J. McCabe Former SVP & Chief Administrative Officer | 2011 | $ | 315,223 | $ | 0 | $ | 272,931 | $ | 0 | $ | 18,065 | $ | 1,938,509 | $ | 2,544,728 | |||||||||||||||
2010 | $ | 289,923 | $ | 0 | $ | 214,424 | $ | 176,062 | $ | 38,457 | $ | 108,277 | $ | 827,143 | ||||||||||||||||
2009 | $ | 280,154 | $ | 0 | $ | 1,247,652 | $ | 114,479 | $ | 30,165 | $ | 53,116 | $ | 1,725,566 | ||||||||||||||||
Arthur G. Meyer Former SVP & General Counsel | 2011 | $ | 318,135 | $ | 0 | $ | 278,579 | $ | 0 | $ | 269,603 | $ | 2,196,881 | $ | 3,063,198 | |||||||||||||||
2010 | $ | 283,123 | $ | 0 | $ | 160,915 | $ | 165,536 | $ | 325,209 | $ | 111,024 | $ | 1,045,807 | ||||||||||||||||
2009 | $ | 273,169 | $ | 36,891 | $ | 656,184 | $ | 147,565 | $ | 185,980 | $ | 112,767 | $ | 1,412,556 | ||||||||||||||||
Gary G. Stephenson Former EVP, Operations | 2011 | $ | 393,808 | $ | 0 | $ | 401,349 | $ | 0 | $ | 9,303 | $ | 888,506 | $ | 1,692,966 | |||||||||||||||
2010 | $ | 357,985 | $ | 32,959 | $ | 980,759 | $ | 253,528 | $ | 33,862 | $ | 126,237 | $ | 1,785,330 | ||||||||||||||||
2009 | $ | 328,223 | $ | 0 | $ | 596,797 | $ | 184,465 | $ | 26,520 | $ | 72,951 | $ | 1,208,956 |
(1) | The amounts under this column relate to additional performance-based bonus amounts paid to these officers that exceeded the amounts they earned under the Company’s Executive Incentive Compensation Plan (EICP) for meeting pre-established EICP annual performance goals. |
(2) | Represents the aggregate grant date fair market values computed in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 718, Compensation – Stock Compensation (“FASB ASC Topic 718”). See Note 12 to the Company’s financial statements that were filed with the SEC March 28, 2012, as part of the Company’s Annual Report on Form 10-K/A for the fiscal year ended December 31, 2011, for assumptions made in determining the valuations for stock awards reported for 2011, 2010 and 2009. LTIP performance share awards granted in 2011, 2010 and 2009 and Career Grant restricted stock awards granted in 2009 under the Company’s Equity Performance and Incentive Plan (EPIP) were subject to performance conditions. The grant date fair values of the LTIP performance share awards included in the table above were based upon the probable outcome that such awards would be earned at target performance levels, excluding the effect of estimated forfeitures. The grant date fair values of the Career Grant restricted stock awards included in the table above were based on the probable outcome that such awards would be fully earned, in each case consistent with the estimate of aggregate compensation costs to be recognized over the applicable service period determined as of the grant date under FASB ASC Topic 718, excluding the effect of estimated forfeitures. The supplemental table set forth below shows the grant date fair market value of each of the LTIP performance share awards granted in 2009, 2010 and 2011 to the named executive officers, assuming that the maximum performance level under the award is achieved. As described above, outstanding equity awards fully, or in the case of LTIP performance shares, partially, vested and were converted into the right to receive the Per-Share Merger Consideration upon consummation of the Merger. |
2009 | 2010 | 2011 | ||||
Paul M. Barbas | 2009-2011 LTIP: $2,018,627 | 2010-2012 LTIP: $1,843,124 | 2011-2013 LTIP: $1,446,549 | |||
Frederick J. Boyle | 2009-2011 LTIP: $657,937 | 2010-2012 LTIP: $637,118 | 2011-2013 LTIP: $522,387 | |||
Scott J. Kelly | 2009 compensation not reported in the Summary Compensation Table | 2010-2012 LTIP: $382,271 | 2011-2013 LTIP: $291,320 | |||
Daniel J. McCabe | 2009-2011 LTIP: $408,202 | 2010-2012 LTIP: $426,666 | 2011-2013 LTIP: $364,336 | |||
Arthur G. Meyer | 2009-2011 LTIP: $265,352 | 2010-2012 LTIP: $312,576 | 2011-2013 LTIP: $369,973 | |||
Gary G. Stephenson | 2009-2011 LTIP: $477,571 | 2010-2012 LTIP: $564,786 | 2011-2013 LTIP: $535,735 |
(3) | Amounts shown include cash awards earned by named executive officers in connection with pre-established annual performance measures under our EICP. For named executive officers who received payments under their separation agreements in lieu of an award under the EICP, such amounts are reflected in the “All Other Compensation” column. |
(4) | The amounts shown reflect the aggregate increase in the actuarial value of the named executive officers’ benefits under all pension plans established by the Company, determined using assumptions consistent with those used in the Company’s financial statements. The Company did not provide above market or preferential earnings on nonqualified deferred compensation in 2011, 2010 or 2009. |
(5) | See the two supplemental tables set forth below for a description of the amounts shown here for 2011. Detailed information about “All Other Compensation” for 2010 and 2009 can be found in our prior Proxy Statements filed with the SEC. |
The following supplemental table sets forth the compensation elements of the 2011 “All Other Compensation” column of the Summary Compensation Table.
All Other Compensation – 2011
Name | Perquisites & Other Personal Benefits (1) | Reimbursements of Taxes (2) | Payments/ Accruals on Termination (3) | Registrant Contributions to Defined Contribution Plans (4) | Dividends Paid on Restricted Stock (5) | Total | ||||||||||||||||||
Paul M. Barbas | $ | 23,593 | $ | 1,142 | $ | 7,097,578 | $ | 160,825 | $ | 50,576 | $ | 7,333,714 | ||||||||||||
Frederick J. Boyle | $ | 22,196 | $ | 141 | $ | 2,261,822 | $ | 59,575 | $ | 59,958 | $ | 2,403,692 | ||||||||||||
Scott J. Kelly | $ | 21,075 | $ | 0 | $ | 0 | $ | 26,596 | $ | 38,298 | $ | 85,969 | ||||||||||||
Daniel J. McCabe | $ | 22,671 | $ | 732 | $ | 1,812,060 | $ | 43,825 | $ | 59,221 | $ | 1,938,509 | ||||||||||||
Arthur G. Meyer | $ | 22,139 | $ | 100 | $ | 2,102,564 | $ | 44,950 | $ | 27,128 | $ | 2,196,881 | ||||||||||||
Gary G. Stephenson | $ | 21,099 | $ | 429 | $ | 729,697 | $ | 67,825 | $ | 69,456 | $ | 888,506 |
(1) | See details for this column in the “Perquisites and Other Personal Benefits – 2011” supplemental table set forth below. |
(2) | Represents amounts for reimbursements of taxes owed with respect to certain perquisites and personal benefits. |
(3) | Represents amounts paid or accrued by the Company in connection with termination of employment. |
(4) | Includes (i) for each named executive officer, the maximum annual matching contribution paid by the Company under the Company’s qualified defined contribution plan of $8,575 for 2011, which plan and matching benefit are available to all Company employees and (ii) for each named executive officer, the Company’s 2011 contribution to the Supplemental Executive Defined Contribution Retirement Plan. |
(5) | Represents dividends paid on unvested restricted stock awards that were not factored into the grant date fair value of the awards. |
The following supplemental table sets forth a summary of the perquisites and other personal benefits paid to named executive officers for 2011 and included in the “All Other Compensation - 2011” supplemental table above.
Perquisites and Other Personal Benefits – 2011
Name | Cash Perquisite Allowance | Personal Travel (1) | Charitable Contribution Matches (2) | Total | ||||||||||||
Paul M. Barbas | $ | 20,000 | $ | 1,593 | $ | 2,000 | $ | 23,593 | ||||||||
Frederick J. Boyle | $ | 20,000 | $ | 196 | $ | 2,000 | $ | 22,196 | ||||||||
Scott J. Kelly | $ | 20,000 | $ | 0 | $ | 1,075 | $ | 21,075 | ||||||||
Daniel J. McCabe | $ | 20,000 | $ | 1,021 | $ | 1,650 | $ | 22,671 | ||||||||
Arthur G. Meyer | $ | 20,000 | $ | 139 | $ | 2,000 | $ | 22,139 | ||||||||
Gary G. Stephenson | $ | 20,000 | $ | 599 | $ | 500 | $ | 21,099 |
(1) | Amounts reflect actual out-of-pocket costs paid by the Company or paid by the individual and reimbursed by the Company for the incremental expense of personal airline travel and food and beverage expenses in connection with select and limited out-of-town business trips on which spouses accompanied the named executive officers. |
(2) | Amounts reflect charitable matching contributions pursuant to a Company charitable matching program available to all directors and employees under which the Company matches contributions to certain organizations up to $2,000 per year. |
Participation Agreements
As indicated in the “Compensation Discussion and Analysis” section of this prospectus starting on page 105, the key components of compensation paid to our executive officers that are reflected in the Summary Compensation Table were established under our executive officer compensation program. The executive officer compensation program and its key components, such as our Executive Incentive Compensation Plan (EICP), Equity and Performance Incentive Plan (EPIP) and Long-Term Incentive Plan (LTIP), are described in the “Compensation Discussion and Analysis” section of this prospectus.
All executive officers sign agreements (“Participation Agreements”) electing to participate in our executive officer compensation program. In connection with the adoption of the program in 2006, the Participation Agreements of certain executive officers, including certain named executive officers, contained provisions waiving a majority of these officers’ rights under pre-existing employment and other agreements. In consideration of their signing the Participation Agreements, these officers retained certain vested and other compensation elements awarded uniquely to them in prior years. These compensation and benefits are included in the compensation tables in this prospectus for the year paid. As a condition to participation in our executive officer compensation program, each executive officer agrees not to, during his or her employment and for a period of two years following termination of employment, solicit Company employees, interfere with the Company’s employee relationships or solicit the Company’s retail customers.
Grants of Plan-Based Awards – 2011
The following table sets forth certain information about the non-equity and equity-based awards made to the named executive officers during 2011.
Estimated Possible Payouts Under Non-Equity Incentive Plan Awards | Estimated Future Payouts Under Equity Incentive Plan Awards | All Other Stock Awards: Number of Shares of Stock or Units (#) | Grant Date Fair Value of Stock and Option Awards ($) | |||||||||||||||||||||||||||||||
Name | Grant Date | Threshold ($) | Target ($) | Maximum ($) | Threshold (#) | Target (#) | Maximum (#) | |||||||||||||||||||||||||||
Paul M. Barbas | ||||||||||||||||||||||||||||||||||
EICP | 02/22/11 | $ | 270,000 | $ | 540,000 | $ | 1,080,000 | |||||||||||||||||||||||||||
2011-2013 LTIP Performance Shares | 02/22/11 | 6,800 | 27,201 | 54,402 | $ | 723,275 | ||||||||||||||||||||||||||||
2011-2013 LTIP Restricted Shares | 02/22/11 | 13,600 | $ | 360,400 | ||||||||||||||||||||||||||||||
Frederick J. Boyle | ||||||||||||||||||||||||||||||||||
EICP | 02/22/11 | $ | 97,500 | $ | 195,000 | $ | 390,000 | |||||||||||||||||||||||||||
2011-2013 LTIP Performance Shares | 02/22/11 | 2,456 | 9,823 | 19,646 | $ | 261,194 | ||||||||||||||||||||||||||||
2011-2013 LTIP Restricted Shares | 02/22/11 | 4,911 | $ | 130,142 | ||||||||||||||||||||||||||||||
Restricted Stock | 02/22/11 | 10,000 | $ | 260,700 | ||||||||||||||||||||||||||||||
Match Shares | 03/31/11 | 47 | $ | 1,288 | ||||||||||||||||||||||||||||||
Scott J. Kelly | ||||||||||||||||||||||||||||||||||
EICP | 02/22/11 | $ | 65,250 | $ | 130,500 | $ | 261,000 | |||||||||||||||||||||||||||
2011-2013 LTIP Performance Shares | 02/22/11 | 1,370 | 5,478 | 10,956 | $ | 145,660 | ||||||||||||||||||||||||||||
2011-2013 LTIP Restricted Shares | 02/22/11 | 2,739 | $ | 72,584 | ||||||||||||||||||||||||||||||
Match Shares | 03/31/11 | 8,673 | $ | 237,727 | ||||||||||||||||||||||||||||||
Daniel J. McCabe | ||||||||||||||||||||||||||||||||||
EICP | 02/22/11 | $ | 80,000 | $ | 160,000 | $ | 320,000 | |||||||||||||||||||||||||||
2011-2013 LTIP Performance Shares | 02/22/11 | 1,713 | 6,851 | 13,702 | $ | 182,168 | ||||||||||||||||||||||||||||
2011-2013 LTIP Restricted Shares | 02/22/11 | 3,425 | $ | 90,763 | ||||||||||||||||||||||||||||||
Arthur G. Meyer | ||||||||||||||||||||||||||||||||||
EICP | 02/22/11 | $ | 81,250 | $ | 162,500 | $ | 325,000 | |||||||||||||||||||||||||||
2011-2013 LTIP Performance Shares | 02/22/11 | 1,739 | 6,957 | 13,914 | $ | 184,987 | ||||||||||||||||||||||||||||
2011-2013 LTIP Restricted Shares | 02/22/11 | 3,479 | $ | 92,194 | ||||||||||||||||||||||||||||||
Match Shares | 03/31/11 | 51 | $ | 1,398 | ||||||||||||||||||||||||||||||
Gary G. Stephenson | ||||||||||||||||||||||||||||||||||
EICP | 02/22/11 | $ | 120,000 | $ | 240,000 | $ | 480,000 | |||||||||||||||||||||||||||
2011-2013 LTIP Performance Shares | 02/22/11 | 2,519 | 10,074 | 20,148 | $ | 267,868 | ||||||||||||||||||||||||||||
2011-2013 LTIP Restricted Shares | 02/22/11 | 5,037 | $ | 133,481 |
With the exception of Mr. Kelly, our named executive officers were entitled to amounts pursuant to their separation agreements in lieu of any annual performance-based cash incentive awards under our Executive Incentive Compensation Plan (“EICP”) for 2011, as described starting on page 133 in the “Employment Termination and Change of Control Payments” section of this prospectus. Mr. Kelly received a grant under the EICP that was based on achievement of annual corporate and individual goals. The EICP is more thoroughly described starting on page 111 in the “Compensation Discussion and Analysis” section of this prospectus.
For the 2011-2013 LTIP cycle, each of the named executive officers was granted an award of performance shares (2/3 of the award) and restricted shares (1/3 of the award) under our Long-Term Incentive Plan (“LTIP”). The LTIP is a long-term performance-based equity incentive plan and is more thoroughly described starting on page 115 in the “Compensation Discussion and Analysis” section of this prospectus. Generally, each officer was required to be employed by the Company or a subsidiary at the end of the applicable cycle, in the case of performance shares, or on the applicable vesting date, in the case of restricted shares, in order to receive the LTIP award for that cycle. LTIP performance share awards reported in the table above were subject to a market
performance condition and the grant date fair values of such awards included in the table were based on the probable outcome that such awards would be earned at target performance, consistent with the estimate of aggregate compensation cost to be recognized over the service period determined as of the grant date under FASB ASC Topic 718, excluding the effect of estimated forfeitures. LTIP performance share awards were valued based on the closing market price of the Company’s common stock on the business day immediately preceding the grant date. Upon consummation of the Merger, the target number of outstanding performance shares vested, pro-rated to the date of the Merger, and outstanding restricted shares fully vested, and such vested shares were converted into the right to receive the Per-Share Merger Consideration.
On February 22, 2011, Mr. Boyle received a restricted stock grant under our EPIP. The EPIP is an equity and incentive plan approved by our shareholders in 2006 and is more thoroughly described starting on page 114 in the “Compensation Discussion and Analysis” section of this prospectus. In addition, our named executive officers, with the exception of Mr. Barbas (and Messrs. McCabe and Stephenson, who maximized their ability to match shares in 2010), were entitled to matching restricted stock awards in 2011 pursuant to a restricted stock matching program under the EPIP that was established by the Board in 2009. The Company agreed to match shares of Company common stock acquired by the executive officer through September 17, 2012, with shares of Company restricted stock (“Match Shares”) based on the table below. Restricted stock awards were valued based on the grant date closing market price of the Company’s common stock. Upon consummation of the Merger, each outstanding share of restricted stock vested and was converted into the right to receive the Per-Share Merger Consideration.
Value of all Company common shares purchased by the executive officer during the Match Period (as a % of 2009 base salary) | Match Shares (as a % of all Company common shares purchased by the executive officer during the Match Period) | ||
Less than or equal to 25% | 25% | ||
25%+ to 50% | 50% | ||
50% + to 100% | 75% | ||
100%+ to 200% | 125% |
Messrs. Boyle, Kelly and Meyer received Match Shares of Company restricted stock in 2011 under the program.
Match Shares were automatically granted to named executive officers on the last day of each quarter based on acquisitions of Company common stock made by the named executive officers in the quarter during the term of the program. In 2010, the Board approved awarding, both prospectively and retroactively during the restricted stock matching program’s term, Match Shares based on purchases of Company common stock in dividend reinvestment plans. Match Shares generally vested three years after they were granted as long as the named executive officer remained continuously employed by the Company or a subsidiary until the vesting date and still owned the acquired Company common shares to which the matched shares related. As noted above, in connection with the Merger, each outstanding share of restricted stock vested and was converted into the right to receive the Per-Share Merger Consideration. In light of the Merger Agreement signed in April 2011, the Company suspended the restricted stock matching program following the March 31, 2011 grant.
Options Exercises and Stock Vested – 2011
The following table sets forth certain information concerning the named executive officers’ vesting of stock awards during 2011. No option awards were exercised by the named executive officers in 2011.
Stock Awards | ||||||||
Name | Number of Shares Acquired on Vesting (#) | Value Realized on Vesting ($) | ||||||
Paul M. Barbas | 126,191 | $ | 3,786,990 | |||||
Frederick J. Boyle | 71,746 | $ | 2,152,380 | |||||
Scott J. Kelly | 44,925 | $ | 1,347,750 | |||||
Daniel J. McCabe | 58,486 | $ | 1,754,580 | |||||
Arthur G. Meyer | 35,951 | $ | 1,079,780 | |||||
Gary G. Stephenson | 73,884 | $ | 2,218,470 |
Pension Benefits – 2011
The following table sets forth the number of years of credited service and the estimated present value of accumulated benefit (in each case, computed as of the pension plan measurement date used for our fiscal year ended December 31, 2011 audited financial statements) for the named executive officers under The Dayton Power and Light Company Retirement Income Plan (the “DP&L Retirement Income Plan”) and our Supplemental Executive Retirement Plan (the “SERP”). During 2011, no payments or benefits under these plans were paid to any of the named executive officers.
Name | Plan Name | Number of Years Credited Service (#) | Present Value of Accumulated Benefit ($) | |||||||
Paul M. Barbas | DP&L Retirement Income Plan | 4 | $ | 110,283 | ||||||
Frederick J. Boyle | DP&L Retirement Income Plan | 5 | $ | 131,425 | ||||||
Scott J. Kelly | DP&L Retirement Income Plan | 16 | $ | 385,922 | ||||||
Daniel J. McCabe | DP&L Retirement Income Plan | 4 | $ | 108,920 | ||||||
Arthur G. Meyer | DP&L Retirement Income Plan | 18 | $ | 905,043 | ||||||
SERP | 12 | $ | 967,974 | |||||||
Gary G. Stephenson | DP&L Retirement Income Plan | 6 | $ | 109,766 |
The DP&L Retirement Income Plan is a qualified defined benefit plan that provides retirement benefits to employees of the Company, including the named executive officers, who have attained age 21 and completed at least one year of service. In general, employees receive pension benefits in an amount equal to (a) 1.25% of the average of the employee’s highest three consecutive annual base salaries for the five years immediately preceding the employee’s termination of employment, plus 0.45% of such average base salary pay in excess of the employee’s Social Security wages, multiplied by (b) the employee’s years of service (not exceeding 30 years). No extra years of service are credited under the terms of the DP&L Retirement Income Plan. Generally, an employee’s normal pension retirement benefits are fully available on his or her 65th birthday. If an employee is no longer employed by the Company prior to vesting in the DP&L Retirement Income Plan (five years), the employee forfeits his or her pension benefits. Early retirement benefits are available to employees at any time once they reach age 55 and have 10 years of vesting service. However, if pension payments start before reaching age 62, the monthly benefit is reduced by 3/12% for each month before age 62. If an employee receives early retirement benefits before age 65, the employee is entitled to receive $187.50 per month until age 65 in addition to the regular pension benefit. Generally, pension benefits under the DP&L Retirement Income Plan are paid in monthly installments upon retirement; however, such benefits may be paid in a lump sum depending on the amount of pension benefits available to the employee. Employees have a right to choose a surviving spouse benefit option. If this option is chosen, pension benefits to the employee are reduced.
The SERP, established January 1, 1977, is a supplemental retirement plan for key employees of the Company to provide retirement benefits to these key employees that were lost due to tax regulations that imposed certain limits on the key employees under the DP&L Retirement Income Plan. Of the named executive officers, only Mr. Meyer participates in the SERP. SERP benefits were no longer awarded after December 2004. Mr. Meyer retained his rights to supplemental retirement benefits under the SERP, but his benefit was frozen at the 2004 level, such that no future changes in years of service or compensation would be reflected in the calculation of his benefit. The benefits under the SERP are generally paid in monthly installments upon retirement; however, Mr. Meyer’s benefits were paid in a lump sum as his separation of service was within the context of a change of control.
See Note 9 to the Company’s financial statements that were filed with the SEC March 28, 2012, as part of the Company’s Annual Report on Form 10-K/A for the fiscal year ended December 31, 2011, for a discussion of the assumptions made in quantifying the present values of the accumulated benefit reflected in the table above for the DP&L Retirement Income Plan.
Nonqualified Deferred Compensation – 2011
The following table sets forth information concerning compensation deferred by our named executive officers in 2011 under our Supplemental Executive Defined Contribution Retirement Plan (“SEDCRP”), our Key Employees Deferred Compensation Plan (“KEDCP”), our 2006 Deferred Compensation Plan for Executives (the “DCP”), and our Long-Term Incentive Plan (“LTIP”) for the 2007-2009 LTIP cycle.
Name | Executive Contributions in Last FY ($)(1) | Registrant Contributions in Last FY ($)(2) | Aggregate Earnings in Last FY ($)(3) | Aggregate Withdrawals/ Distributions ($) | Aggregate Balance at Last FYE ($)(4) | |||||||||||||||
Paul M. Barbas | ||||||||||||||||||||
SEDCRP | $ | 0 | $ | 152,250 | $ | (15,692 | ) | $ | (660,363 | ) | $ | 0 | ||||||||
Frederick J. Boyle | ||||||||||||||||||||
SEDCRP | $ | 0 | $ | 51,000 | $ | (1,758 | ) | $ | (187,492 | ) | $ | 0 | ||||||||
DCP | $ | 95,731 | $ | 0 | $ | (2,294 | ) | $ | 0 | $ | 93,437 | |||||||||
Scott J. Kelly | ||||||||||||||||||||
SEDCRP | $ | 0 | $ | 18,021 | $ | 622 | $ | (108,108 | ) | $ | 18,021 | |||||||||
Daniel J. McCabe | ||||||||||||||||||||
SEDCRP | $ | 0 | $ | 35,250 | $ | 524 | $ | (148,908 | ) | $ | 0 | |||||||||
Arthur G. Meyer | ||||||||||||||||||||
SEDCRP | $ | 0 | $ | 36,375 | $ | 654 | $ | (148,579 | ) | $ | 36,375 | |||||||||
KEDCP | $ | 0 | $ | 0 | $ | (2,232 | ) | $ | 0 | $ | 273,469 | |||||||||
2007-2009 LTIP | $ | 0 | $ | 0 | $ | 31,476 | $ | (230,880 | ) | $ | 0 | |||||||||
Gary G. Stephenson | ||||||||||||||||||||
SEDCRP | $ | 0 | $ | 59,250 | $ | 6,123 | $ | (264,807 | ) | $ | 0 |
(1) | All contributions set forth in this column were made pursuant to the Company’s 2006 Deferred Compensation Plan for Executives and are also reported under the “Salary” column for 2011 in the Summary Compensation Table. |
(2) | All contributions set forth in this column were made under the Company’s Supplemental Executive Defined Contribution Retirement Plan and are also reported under the “All Other Compensation” column for 2011 in the Summary Compensation Table. |
(3) | None of the aggregate earnings set forth in this table are included in the Summary Compensation Table because such aggregate earnings were not above-market earnings. |
(4) | The following SEDCRP amounts were reported as compensation under the “All Other Compensation” column for 2010 in the Summary Compensation Table: Mr. Barbas – $164,704; Mr. Boyle – $50,845; Mr. Kelly – $28,812; Mr. McCabe – $33,609; and Mr. Stephenson - $60,973. The following SEDCRP amounts were reported as compensation under the “All Other Compensation” column for 2009 in the Summary Compensation Table: Mr. Barbas - $131,645; Mr. Boyle – $35,888; Mr. McCabe – $21,372; and Mr. Meyer – $30,848. Messrs. Kelly and Stephenson’s 2009 compensation amounts and Mr. Meyer’s 2010 compensation amount were not required to be reported in the Summary Compensation Table. In addition, with respect to Mr. Boyle’s DCP balance, $95,731 was reported under the “Salary” column for 2011 in the Summary Compensation Table. Upon consummation of the Merger, all deferred performance shares (Mr. Meyer’s 2007-2009 LTIP) were converted into the right to receive the Per-Share Merger Consideration. |
The SEDCRP is a nonqualified defined contribution retirement plan that provides additional retirement benefits to certain executive officers, including the named executive officers, beyond the dollar limitation on compensation imposed under U.S. tax laws. Each year, the Company records a contribution for each named executive officer equal to 15% of the officer’s annual base salary and EICP cash bonus award that exceeds the annual compensation limits imposed by the tax laws ($245,000 in 2011). Vesting for these benefits occurs after five years of Company service under the same terms as The Dayton Power and Light Company Retirement Income Plan or upon death, disability or a change of control. Upon consummation of the Merger, our executive officers were entitled to vesting of unvested amounts credited to them under the SEDCRP that were attributable to company contributions. Our
named executive officers were all vested under the SEDCRP at the consummation of the Merger. 2011 account balances were paid out in a lump sum within 30 days following the closing of the Merger.
We also maintain the 2006 Deferred Compensation Plan for Executives (the “DCP”), and the Key Employees Deferred Compensation Plan (the “KEDCP”), which allowed executive officers the opportunity to defer the receipt of all or a portion of their earned pre-tax base salaries and incentive compensation cash payments. The DCP was adopted in 2006 as a successor to the KEDCP and all deferrals made after December 2006 were made under the DCP. If an executive officer elects to defer any amount of his or her cash compensation, such deferred amounts are not reported (for federal and state tax purposes) as compensation in the year earned and are credited to the individual’s deferred compensation plan account. Deferred amounts under either the DCP or the KEDCP are credited to a separate account for the participant and hypothetical investments are made and credited as designated by the participant. Deferred compensation plan account balances accrue earnings based on the investment options selected by the participant. Participants may change their investment selections quarterly. Plan account balances generally are paid following the termination of the participant’s employment with us (subject to a hardship exception for early withdrawal). Payments are made in a lump sum or in annual installments over a period of up to 20 years, as determined by the participant’s deferral election form. We provide for our obligations to participants under the KEDCP through a master trust but the DCP is an unfunded plan. However, upon consummation of the Merger, there were sufficient assets in the master trust to fully provide for the benefits that would become payable to our executive officers under the DCP due to their subsequent termination of employment.
The LTIP had a deferral feature that granted to each named executive officer the right to defer receipt of earned performance shares under the LTIP pursuant to a written election completed by the executive. Any performance shares so deferred were credited to an account in the executive officer’s name and were 100% vested at all times. Deferred performance shares earned dividend equivalents as declared and paid on Company common stock that were reinvested in additional performance shares, but were not entitled to voting rights until distribution to the participant. The minimum deferral period was the lesser of one year and termination of employment, subject to a hardship exception for early withdrawal. No named executive officers deferred any of their earned LTIP performance shares, except Mr. Meyer who deferred all of his performance shares earned (net of shares withheld for local and FICA taxes) on December 31, 2009 for the 2007 – 2009 LTIP cycle. Upon consummation of the Merger, all deferred performance shares were converted into the right to receive the Per-Share Merger Consideration.
Employment Termination and Change of Control Payments
Set forth below are a discussion and two tables describing payments that could be made to named executive officers due to the termination of their employment with us or in the context of a change of control of our Company. The discussion describes generally the payments and benefits that these named executive officers were entitled to receive under our Severance Pay and Change of Control Plan (the “Severance Plan”) and other plans and agreements that contain termination and change of control provisions (excluding plans and agreements that did not discriminate in scope, terms or operation in favor of executive officers and are generally available to all Company salaried employees). The first table summarizes the types of payments and benefits, as applicable, that the named executive officers would be entitled to under various scenarios. The second table sets forth the values of these payments and benefits, on a per item basis, assuming, other than for Mr. Stephenson, whose employment with the Company terminated on December 27, 2011, that the named executive officers’ terminations of employment or a change of control occurred on December 31, 2011. Messrs. Barbas, Boyle, and McCabe’s employment with the Company actually terminated on December 31, 2011.
If the Company terminated a named executive officer without cause and not due to death or disability, and not within a change of control setting, the named executive officer would have been entitled to receive under our Severance Plan an amount equal to his annual base salary rate then in effect and target Executive Incentive Compensation Plan (“EICP”) cash award for the year. In addition, the named executive officer would be entitled to six months of Company paid outplacement services and to continued participation, at the Company’s cost, in the Company’s medical plan for twelve months or until the named executive officer became eligible for coverage under another medical plan (subject to IRS limitations). Cash severance payments to a named executive outside of a change of control setting were payable in equal installments over a twelve-month period according to the Company’s payroll policies, assuming there were no IRS restrictions impacting the payments.
If, in connection with a change of control of our Company and within a period of time (two years for our CEO and one year for each other named executive officer), a named executive officer is terminated without cause and not due to death or disability, or resigns for good reason, the named executive officer would be entitled to receive under the Severance Plan (i) an applicable multiple (three times for our CEO and two times for each other named executive officer) of his annual base salary rate then in effect, of his target EICP cash award for the year and of a $20,000 perquisite allowance amount, (ii) annual contributions (three years for our CEO and two years for each other named executive officer) that the Company would have made for the named executive officer under our Supplemental Executive Defined Contribution Retirement Plan (the “SEDCRP”), (iii) his target EICP cash award pro-rated to the date of termination, (iv) vesting of his target equity awards under our Equity and Performance Incentive Plan pro-rated to the date of termination, (v) six months of Company-paid outplacement services and (vi) subject to IRS limitations, continued participation in the Company’s medical plan (three years for our CEO and two years for each other named executive officer) at the Company’s cost. A named executive officer also would be entitled to receive an additional payment to reimburse him for excise taxes (and any associated taxes) imposed on his change of control payments and benefits under the Severance Plan and any other Company plans or agreements if such payments and benefits exceeded 110% of the safe harbor amount that would not subject the executive to these taxes. If the amount of the change of control payments and benefits were equal to or less than 110% of the safe harbor amount, the change of control payments and benefits to the executive officer would be reduced to the extent necessary to avoid imposition of excise taxes. By paying an executive’s excise and associated taxes, the executive was able to retain the same amount that he would have received had the excise taxes not been imposed. The Company did not offer this tax gross-up benefit to any new participant in the Severance Plan on or after January 1, 2010.
Under the Severance Plan,
· | “cause” is generally defined as (i) any willful or negligent material violation of any applicable securities laws (including the Sarbanes-Oxley Act of 2002), (ii) any act of fraud, intentional misrepresentation, embezzlement, misappropriation or conversion of any asset or business opportunity of the Company, (iii) a conviction of, or entering into a plea of no contest to, a felony, (iv) an intentional, repeated or continuing violation of any of the Company’s policies or procedures that occurs or continues after the Company has given notice of a material violation thereof, or (v) a breach of a written covenant or agreement with the Company, which is material and which is not cured within 30 days after written notice thereof from the Company; |
· | “good reason” is generally defined as, following a change of control, (i) a demotion or a material reduction in the participant’s position, duties, responsibilities, and status with the Company, (ii) a material reduction by the Company of a participant’s base salary, or (iii) the relocation of the Company’s principal executive offices more than 50 miles from their current location or requiring a participant to be based at a location more than 50 miles from his or her location on the date of the change in control; and |
· | “change of control” is generally defined as the consummation of any change of control of DPL, or its principal subsidiary, DP&L, of a nature that would be required to be reported in response to Item 6(e) of Schedule 14A under the Exchange Act, as determined by the Board of Directors of DPL in its sole discretion, including, subject to specified exceptions, any of the following: (i) a person becoming the beneficial owner of 25% or more of the combined voting power of the then outstanding voting stock of DPL or DP&L if the acquisition of such beneficial ownership is not approved by the Board of Directors of DPL prior to the acquisition or 50% or more of such combined voting power in all other cases, subject to specified exceptions; (ii) the consummation of certain mergers, consolidations, combinations or share acquisitions involving DPL or DP&L; (iii) a sale, lease, exchange or other transfer or disposition of all or substantially all of the assets of DPL or DP&L; (iv) board members (or their successors) ceasing to constitute a majority of the Board of Directors of DPL or DP&L; or (v) shareholder approval of a complete liquidation or dissolution of DPL or DP&L. |
Under the Severance Plan, cash severance payments payable to a named executive officer in a change of control setting are generally payable in a lump sum as soon as practicable after the termination date, assuming there are no IRS restrictions impacting the payments. Whether or not a change of control occurs, no payment is to be made under the Severance Plan to a terminated named executive officer unless he signs a release that waives claims
against the Company and contains confidentiality and non-disparagement covenants and agrees to a non-solicitation clause that prohibits the solicitation of Company employees and retail customers for two years after termination. A copy of our Severance Plan was filed with the SEC on February 22, 2008, as part of our Annual Report on Form 10-K for fiscal year ended December 31, 2007.
Aside from our Severance Plan, the following Company plans and agreements (excluding plans and agreements that do not discriminate in scope, terms or operation in favor of executive officers and are generally available to all Company salaried employees) contain provisions that provide or enhance payments or benefits to named executive officers due to termination and/or a change of control.
· | As described above, in connection with the consummation of the Merger, unvested shares of restricted stock and performance shares were vested (on a full or prorated basis, respectively) and cashed out and unvested SEDCRP contributions were fully vested and account balances were distributed. As a result, as of December 31, 2011 (or December 27, 2011 for Mr. Stephenson), none of the named executive officers had any unvested restricted or performance shares or SEDCRP contributions. |
· | Upon the termination of his employment, Mr. Meyer is entitled to lifetime Company-paid health insurance coverage for himself and his dependents under the Company’s Executive Healthcare Plan and to payments based on his accrued benefits under the Company’s SERP and his vested benefits under the KEDCP in accordance with the provisions of the plans. |
· | In addition, as described below, our named executive officers, other than Mr. Kelly, are entitled to certain benefits under their separation agreements with the Company. |
The following table sets forth a summary of the types of payments and benefits discussed generally above that named executive officers would be entitled to receive under various scenarios in connection with an employment termination or a change of control of the Company.
Types of Change of Control and Termination Payments and Benefits
Benefit | Voluntary Termination | Termination For Cause | Termination Due to Death | Termination Due to Disability | Termination Without Cause | Change of Control | Change of Control and Subsequent Termination (1) |
Cash Severance: | |||||||
Annual Base Salary and Target EICP Award Amount | None | None | None | None | 1X | None | CEO 3X Officers 2X |
Target EICP Award | None | None | None | None | None | None | Pro Rata |
$20,000 Cash Allowance Amount | None | None | None | None | None | None | CEO 3X Officers 2X |
SEDCRP Contribution Value | None | None | None | None | None | None | CEO 3X Officers 2X |
Retirement Benefits: | |||||||
SEDCRP Vested Amounts | Full Benefits | Full Benefits | Full Benefits | Full Benefits | Full Benefits | Full Benefits | Full Benefits |
KEDCP Vested Amounts | Full Benefits | Full Benefits | Full Benefits | Full Benefits | Full Benefits | Full Benefits | Full Benefits |
2006 DCP Vested Amounts | Full Benefits | Full Benefits | Full Benefits | Full Benefits | Full Benefits | Full Benefits | Full Benefits |
Executive Healthcare Plan | Full Benefits | Full Benefits | Full Benefits | Full Benefits | Full Benefits | None | Full Benefits |
SERP Vested Amounts | Full Benefits | Full Benefits | Full Benefits | Full Benefits | Full Benefits | None | Full Benefits |
Other Benefits: | |||||||
Medical Plan Coverage | None | None | None | None | 12 months | None | CEO 3 years Officers 2 years |
Outplacement Services | None | None | None | None | 6 months | None | 6 Months |
Excise Tax Gross-Ups | None | None | None | None | None | None | Excise and associated taxes |
(1) | For amounts under this column that are payable under our Severance Plan, the named executive officer must be terminated without cause and not due to death or disability, or must resign with good reason within two years (CEO) or one year (other named executive officers). |
The following table sets forth in detail the value of the payments and benefits discussed generally above that each named executive officer (other than Mr. Stephenson) would have been entitled to receive, on a per item basis, due to a change of control of our Company and/or an employment termination on December 31, 2011. The value of payments and benefits shown for Mr. Stephenson in the table reflect the amounts that he received in connection with his termination of employment on December 27, 2011. Payments and benefits payable to Messrs. Barbas, Boyle, McCabe, Meyer and Stephenson under their respective separation agreements in connection with their actual terminations of employment with the Company are described further below.
Value of Change of Control and Termination Payments and Benefits – December 31, 2011
Benefit | Voluntary Termination | Termination For Cause | Termination Due to Death | Termination Due to Disability | Termination Without Cause | Change of Control | Change of Control and Subsequent Termination (4) | |||||||||||||||||||||
Annual Base Salary and Target EICP Award Amount | ||||||||||||||||||||||||||||
Paul M. Barbas | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 1,260,000 | $ | 0 | $ | 3,780,000 | ||||||||||||||
Frederick J. Boyle | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 585,000 | $ | 0 | $ | 1,170,000 | ||||||||||||||
Scott J. Kelly | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 420,500 | $ | 0 | $ | 841,000 | ||||||||||||||
Daniel J. McCabe | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 480,000 | $ | 0 | $ | 960,000 | ||||||||||||||
Arthur G. Meyer | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 487,500 | $ | 0 | $ | 975,000 | ||||||||||||||
Gary G. Stephenson | — | — | — | — | — | — | $ | 622,029 | (5) | |||||||||||||||||||
Pro-Rated Target EICP Award | ||||||||||||||||||||||||||||
Paul M. Barbas | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 540,000 | ||||||||||||||
Frederick J. Boyle | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 195,000 | ||||||||||||||
Scott J. Kelly | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 130,500 | ||||||||||||||
Daniel J. McCabe | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 160,000 | ||||||||||||||
Arthur G. Meyer | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 162,500 | ||||||||||||||
Gary G. Stephenson | — | — | — | — | — | — | $ | 80,000 | ||||||||||||||||||||
$20,000 Cash Allowance Amount | ||||||||||||||||||||||||||||
Paul M. Barbas | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 60,000 | ||||||||||||||
Frederick J. Boyle | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 40,000 | ||||||||||||||
Scott J. Kelly | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 40,000 | ||||||||||||||
Daniel J. McCabe | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 40,000 | ||||||||||||||
Arthur G. Meyer | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 40,000 | ||||||||||||||
Gary G. Stephenson | — | — | — | — | — | — | $ | 0 | ||||||||||||||||||||
Supplemental Executive Defined Contribution Retirement Plan Contribution Value | ||||||||||||||||||||||||||||
Paul M. Barbas | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 456,750 | ||||||||||||||
Frederick J. Boyle | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 102,000 | ||||||||||||||
Scott J. Kelly | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 52,650 | ||||||||||||||
Daniel J. McCabe | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 70,500 | ||||||||||||||
Arthur G. Meyer | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 72,750 | ||||||||||||||
Gary G. Stephenson | — | — | — | — | — | — | $ | 0 | ||||||||||||||||||||
Vested Supplemental Executive Defined Contribution Retirement Plan Amounts | ||||||||||||||||||||||||||||
Paul M. Barbas | $ | 152,250 | $ | 152,250 | $ | 152,250 | $ | 152,250 | $ | 152,250 | $ | 152,250 | $ | 152,250 | ||||||||||||||
Frederick J. Boyle | $ | 51,000 | $ | 51,000 | $ | 51,000 | $ | 51,000 | $ | 51,000 | $ | 51,000 | $ | 51,000 | ||||||||||||||
Scott J. Kelly | $ | 18,021 | $ | 18,021 | $ | 18,021 | $ | 18,021 | $ | 18,021 | $ | 18,021 | $ | 18,021 | ||||||||||||||
Daniel J. McCabe | $ | 35,250 | $ | 35,250 | $ | 35,250 | $ | 35,250 | $ | 35,250 | $ | 35,250 | $ | 35,250 | ||||||||||||||
Arthur G. Meyer | $ | 36,375 | $ | 36,375 | $ | 36,375 | $ | 36,375 | $ | 36,375 | $ | 36,375 | $ | 36,375 | ||||||||||||||
Gary G. Stephenson | — | — | — | — | — | — | $ | 59,250 | ||||||||||||||||||||
Vested Key Employees Deferred Compensation Plan Amounts | ||||||||||||||||||||||||||||
Paul M. Barbas | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | ||||||||||||||
Frederick J. Boyle | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | ||||||||||||||
Scott J. Kelly | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | ||||||||||||||
Daniel J. McCabe | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 |
Benefit | Voluntary Termination | Termination For Cause | Termination Due to Death | Termination Due to Disability | Termination Without Cause | Change of Control | Change of Control and Subsequent Termination (4) | |||||||||||||||||||||
Arthur G. Meyer | $ | 273,469 | $ | 273,469 | $ | 273,469 | $ | 273,469 | $ | 273,469 | $ | 273,469 | $ | 273,469 | ||||||||||||||
Gary G. Stephenson | — | — | — | — | — | — | $ | 0 | ||||||||||||||||||||
Vested 2006 Deferred Compensation Plan for Executives Amounts | ||||||||||||||||||||||||||||
Paul M. Barbas | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | ||||||||||||||
Frederick J. Boyle | $ | 93,437 | $ | 93,437 | $ | 93,437 | $ | 93,437 | $ | 93,437 | $ | 93,437 | $ | 93,437 | ||||||||||||||
Scott J. Kelly | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | ||||||||||||||
Daniel J. McCabe | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | ||||||||||||||
Arthur G. Meyer | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | ||||||||||||||
Gary G. Stephenson | — | — | — | — | — | — | $ | 0 | ||||||||||||||||||||
Executive Healthcare Plan(1) | ||||||||||||||||||||||||||||
Paul M. Barbas | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | ||||||||||||||
Frederick J. Boyle | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | ||||||||||||||
Scott J. Kelly | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | ||||||||||||||
Daniel J. McCabe | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | ||||||||||||||
Arthur G. Meyer | $ | 303,902 | $ | 303,902 | $ | 303,902 | $ | 303,902 | $ | 303,902 | $ | 0 | $ | 303,902 | ||||||||||||||
Gary G. Stephenson | — | — | — | — | — | — | $ | 0 | ||||||||||||||||||||
Vested Supplemental Executive Retirement Plan Amounts | ||||||||||||||||||||||||||||
Paul M. Barbas | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | ||||||||||||||
Frederick J. Boyle | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | ||||||||||||||
Scott J. Kelly | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | ||||||||||||||
Daniel J. McCabe | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | ||||||||||||||
Arthur G. Meyer | $ | 967,974 | $ | 967,974 | $ | 967,974 | $ | 967,974 | $ | 967,974 | $ | 0 | $ | 967,974 | ||||||||||||||
Gary G. Stephenson | — | — | — | — | — | — | $ | 0 | ||||||||||||||||||||
Medical Plan Coverage(2) | ||||||||||||||||||||||||||||
Paul M. Barbas | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 13,524 | $ | 0 | $ | 52,860 | ||||||||||||||
Frederick J. Boyle | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 13,524 | $ | 0 | $ | 33,192 | ||||||||||||||
Scott J. Kelly | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 13,524 | $ | 0 | $ | 33,192 | ||||||||||||||
Daniel J. McCabe | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 19,668 | $ | 0 | $ | 39,336 | ||||||||||||||
Arthur G. Meyer | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 13,524 | $ | 0 | $ | 33,192 | ||||||||||||||
Gary G. Stephenson | — | — | — | — | — | — | $ | 19,668 | ||||||||||||||||||||
Outplacement Services | ||||||||||||||||||||||||||||
Paul M. Barbas | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 8,000 | $ | 0 | $ | 8,000 | ||||||||||||||
Frederick J. Boyle | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 8,000 | $ | 0 | $ | 8,000 | ||||||||||||||
Scott J. Kelly | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 8,000 | $ | 0 | $ | 8,000 | ||||||||||||||
Daniel J. McCabe | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 8,000 | $ | 0 | $ | 8,000 | ||||||||||||||
Arthur G. Meyer | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 8,000 | $ | 0 | $ | 8,000 | ||||||||||||||
Gary G. Stephenson | — | — | — | — | — | — | $ | 8,000 | ||||||||||||||||||||
Excise Tax Gross-Ups(3) | ||||||||||||||||||||||||||||
Paul M. Barbas | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 1,890,978 | ||||||||||||||
Frederick J. Boyle | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 591,376 | ||||||||||||||
Scott J. Kelly | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | ||||||||||||||
Daniel J. McCabe | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | ||||||||||||||
Arthur G. Meyer | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | ||||||||||||||
Gary G. Stephenson | — | — | — | — | — | — | $ | 0 | ||||||||||||||||||||
Total | ||||||||||||||||||||||||||||
Paul M. Barbas | $ | 152,250 | $ | 152,250 | $ | 152,250 | $ | 152,250 | $ | 1,433,774 | $ | 152,250 | $ | 6,940,838 | ||||||||||||||
Frederick J. Boyle | $ | 144,437 | $ | 144,437 | $ | 144,437 | $ | 144,437 | $ | 750,961 | $ | 144,437 | $ | 2,284,005 | ||||||||||||||
Scott J. Kelly | $ | 18,021 | $ | 18,021 | $ | 18,021 | $ | 18,021 | $ | 460,045 | $ | 18,021 | $ | 1,123,363 | ||||||||||||||
Daniel J. McCabe | $ | 35,250 | $ | 35,250 | $ | 35,250 | $ | 35,250 | $ | 542,918 | $ | 35,250 | $ | 1,313,086 | ||||||||||||||
Arthur G. Meyer | $ | 1,581,720 | $ | 1,581,720 | $ | 1,581,720 | $ | 1,581,720 | $ | 2,090,744 | $ | 309,844 | $ | 2,873,162 | ||||||||||||||
Gary G. Stephenson | — | — | — | — | — | — | $ | 788,947 | ||||||||||||||||||||
TOTAL | $ | 1,931,678 | $ | 1,931,678 | $ | 1,931,678 | $ | 1,931,678 | $ | 5,278,442 | $ | 659,802 | $ | 15,323,401 |
(1) | The Executive Healthcare Plan amount for Mr. Meyer assumes a monthly payment of $1,072 which is increased based on the assumed health care cost trend rates for 2011 set forth in Note 9 to the Company’s financial statements filed with the SEC March 28, 2012, as part of the Company’s Annual Report on Form 10-K/A for the fiscal year ended December 31, 2011, for Mr. Meyer’s actuarially determined life expectancy, and then discounted to December 31, 2011 at 4.62% per year. |
(2) | The Medical Plan Coverage amounts are based on actual monthly premium costs for 2012 (Mr. Barbas - $1,127, Mr. Boyle - $1,127, Mr. Kelly - $1,127, Mr. McCabe - $1,639, Mr. Meyer - $1,127 and Mr. Stephenson - $1,639) and on the highest monthly employee health insurance premium under the Company’s medical plan of $1,639 for 2013 and beyond. |
(3) | Executive officers who receive benefits within the change of control provisions under our Severance Plan are subject to non-solicitation and other restrictive covenants. Since the Company expects to enforce these restrictive covenants in a change of control setting, the magnitude of the excise taxes and resulting gross-up amounts may be reduced under Section 280G. The Excise Tax Gross-Ups amounts listed in this table were calculated in accordance with Section 280G of the Internal Revenue Code and assume the highest marginal tax rates. |
(4) | For amounts under this column that are payable under our Severance Plan, the named executive officer must be terminated without cause and not due to death or disability, or must resign with good reason within two years (CEO) or one year (other named executive officers). |
(5) | This amount represents Mr. Stephenson’s base salary plus his target EICP award minus $17,971, the amount by which his benefits were reduced to avoid the imposition of excise taxes. |
Mr. Barbas’s Separation Agreement
In connection with his resignation as an executive officer of the Company on December 31, 2011, Mr. Barbas agreed to provide consulting services to the Company through January 31, 2012 and to customary release of claims, confidentiality, non-disparagement, and non-solicitation provisions. The Company agreed to provide Mr. Barbas with (i) $12,000 in exchange for his consulting services; (ii) a separation payment equal to $3,780,000 (representing three times his base pay and three times his target annual incentive award under the EICP); (iii) a lump sum payment equal to $540,000 (representing his 2011 target annual incentive award); (iv) a lump sum payment equal to $456,750 (representing the amount that would have been credited to his SEDCRP account over three years); (v) paid medical insurance premiums for up to three years; (vi) paid outplacement services for six months; (vii) a lump sum payment equal to $60,000 and (viii) a gross-up payment for excise taxes incurred under Section 280G of the Internal Revenue Code.
Mr. Boyle’s Separation Agreement
In connection with his resignation as an executive officer of the Company on December 31, 2011, Mr. Boyle agreed to provide consulting services to the Company through February 28, 2012 and to customary release of claims, confidentiality, non-disparagement, and non-solicitation provisions. The Company agreed to provide Mr. Boyle with (i) $13,000 in exchange for his consulting services; (ii) a separation payment equal to $1,170,000 (representing two times his base pay and two times his target annual incentive award under the EICP); (iii) a lump sum payment equal to $195,000 (representing his 2011 target annual incentive award); (iv) a lump sum payment equal to $102,000 (representing the amount that would have been credited to his SEDCRP account over two years); (v) paid medical insurance premiums for up to two years; (vi) paid outplacement services for six months; (vii) a lump sum payment equal to $40,000; and (viii) a gross-up payment for excise taxes incurred under Section 280G of the Internal Revenue Code.
Mr. McCabe’s Separation Agreement
In connection with his resignation as an executive officer of the Company on December 31, 2011, Mr. McCabe agreed to customary release of claims, confidentiality, non-disparagement, and non-solicitation provisions. The Company agreed to provide Mr. McCabe with (i) a separation payment equal to $960,000 (representing two times his base pay and two times his 2011 target annual incentive award under the EICP); (ii) a lump sum payment equal to $160,000 (representing his 2011 target annual incentive award); (iii) a lump sum payment equal to $70,500 (representing the amount that would have been credited to his SEDCRP account over two years); (iv) paid medical insurance premiums for up to two years; (v) paid outplacement services for six months; (vi) a lump sum payment equal to $40,000; (vii) and a gross-up payment for excise taxes incurred under Section 280G of the Internal Revenue Code.
Mr. Meyer’s Separation Agreement
In connection with his retirement as an executive officer of the Company, the Company agreed to provide Mr. Meyer with certain payments and benefits in exchange for his promise to continue his employment with the Company through June 30, 2012. Under the agreement, Mr. Meyer received (i) a lump sum payment equal to $162,500 (representing his 2011 target annual incentive award) by March 15, 2012; and (ii) an “initial success bonus” of $40,625 on March 31, 2012 by complying with the terms of the agreement which specified that the
Company file an electric security plan or market rate option with the Public Utilities Commission of Ohio on or before March 31, 2012. A “second success bonus” in the amount of $40,625 was not achieved because the Company did not obtain a settlement, order or other equivalent agreement or arrangement approving an electric security plan or market rate option from the Public Utilities Commission of Ohio by June 30, 2012. Furthermore, in consideration for a customary release of claims, confidentiality, non-disparagement, and non-solicitation provisions, the Company agreed to provide Mr. Meyer with (i) a separation payment equal to $975,000 (representing two times his 2011 base pay and two times his 2011 target incentive award under the EICP); (ii) a lump sum payment equal to $72,750 (representing the amount that would have been credited to his SEDCRP account for two years); (iii) paid medical insurance premiums for up to two years; (iv) lifetime paid medical coverage under the Company’s Executive Healthcare Plan following the two years of paid medical premiums; (v) outplacement services for six months; (vi) a lump sum amount equal to $40,000; and (vii) a gross-up payment for excise taxes incurred under Section 280G of the Internal Revenue Code.
Mr. Stephenson’s Separation Agreement
In connection with his resignation as an executive officer of the Company on December 27, 2011, Mr. Stephenson agreed to customary release of claims, confidentiality, non-disparagement, and non-solicitation provisions. The Company agreed to provide Mr. Stephenson with (i) a lump sum payment equal to $640,000; (ii) a lump sum payment equal to $80,000; (iii) a lump sum payment equal to $59,250 (representing the amount that would have been credited to his SEDCRP account for 2011); (iv) paid medical insurance premiums for up to one year; (v) paid outplacement services for six months; (vi) a gross-up or direct payment for excise taxes incurred under Section 280G of the Internal Revenue Code, if applicable, and (vii) attorney fees in the amount of $28,000. However, pursuant to the terms of the Severance Plan, Mr. Stephenson’s actual payments and benefits were reduced by $17,971 to avoid the imposition of excise taxes.
COMPENSATION OF DIRECTORS
Pursuant to the Company’s Corporate Governance Guidelines, the Nominating and Corporate Governance Committee, in consultation with the Compensation Committee, was responsible for recommending the compensation program for directors. A director who was also an employee of the Company did not receive additional compensation for service as a director. The following table shows the annual compensation program for non-employee directors that was in place from 2007 until the Company was acquired by the AES Corporation in 2011.
Annual Board Cash Retainer | $ | 54,000 | ||
Annual Board Equity Retainer (paid in restricted stock units of DPL Inc.) | $ | 54,000 | ||
Chairman of the Board Annual Cash Retainer | $ | 125,000 | ||
Committee Chair Annual Cash Retainer | $ | 10,000 | ||
Board Meeting and Committee Meeting Cash Fees (per in-person meeting) | $ | 1,500 | ||
Board Meeting and Committee Meeting Cash Fees (per telephonic meeting) | $ | 750 |
The following table sets forth compensation earned by non-employee directors of the Board during the fiscal year ending December 31, 2011. Mr. Barbas, who served as a director and our President and Chief Executive Officer, did not receive additional compensation for his services as a director.
Director Compensation – 2011
Name | Fees Earned or Paid in Cash ($) | Stock Awards ($)(1) | Option Awards ($)(2) | All Other Compensation ($)(3) | Total ($) | |||||||||||||||
Paul M. Barbas | N/A | N/A | N/A | N/A | N/A | |||||||||||||||
Robert D. Biggs | $ | 72,000 | $ | 54,114 | $ | 0 | $ | 3,942 | $ | 130,056 | ||||||||||
Paul R. Bishop | $ | 88,750 | $ | 54,114 | $ | 0 | $ | 1,942 | $ | 144,806 | ||||||||||
Frank F. Gallaher | $ | 82,500 | $ | 54,114 | $ | 0 | $ | 3,942 | $ | 140,556 | ||||||||||
Barbara S. Graham | $ | 94,750 | $ | 54,114 | $ | 0 | $ | 1,942 | $ | 150,806 | ||||||||||
Glenn E. Harder | $ | 188,011 | $ | 54,114 | $ | 0 | $ | 1,942 | $ | 244,067 | ||||||||||
General Lester L. Lyles (Retired) | $ | 76,500 | $ | 54,114 | $ | 0 | $ | 3,942 | $ | 134,556 | ||||||||||
Pamela B. Morris | $ | 78,750 | $ | 54,114 | $ | 0 | $ | 1,942 | $ | 134,806 | ||||||||||
Dr. Ned J. Sifferlen | $ | 92,500 | $ | 54,114 | $ | 0 | $ | 3,942 | $ | 150,556 |
(1) | Represents the grant date fair market value, computed in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 718, Compensation – Stock Compensation (“FASB ASC Topic 718”), of $54,114 for the 1,799 restricted stock units granted to each non-employee director on September 23, 2011, as part of the 2011 annual Board retainer. The number of restricted stock units granted to each non-employee director on September 23, 2011 was computed by dividing the value of the current annual Board equity retainer of $54,000 by $30.02, which was the average closing market price of the Company’s common stock over the 30-day period preceding the grant date of September 23, 2011. The grant date fair value reported in the table for each non-employee director was computed by multiplying the 1,799 restricted stock units granted to each director by the closing market price of the Company’s common stock on September 22, 2011, the date immediately preceding the grant date, of $30.08 per share. Upon the consummation of the Merger, unvested restricted stock units vested and each outstanding restricted stock unit was converted into a right to receive the Per-Share Merger Consideration. |
(2) | No options were awarded to directors in 2011. |
(3) | The amounts shown include: (i) perquisites and personal benefits, (ii) amounts reimbursed for the payment of taxes, (iii) charitable matching program payments and (iv) dividends credited in 2011 on stock awards of restricted stock units that were not factored into the grant date fair value of the stock awards. The amount of each of these four categories of All Other Compensation for each non-employee director was less than $10,000. Of the total amounts shown, each non-employee director received $90 for the reimbursement of taxes and the following non-employee directors received the following charitable matching program payments for 2011 pursuant to a Company charitable matching program available to all directors and employees under which the Company matched contributions to certain organizations up to $2,000 per year: Mr. Biggs – $2,000; Mr. Gallaher – $2,000; Gen. Lyles – $2,000; and Dr. Sifferlen – $2,000. |
Restricted stock units issued to directors in connection with the Company’s director compensation program were issued under the Company’s Equity Performance and Incentive Plan and governed by individual award agreements. The number of restricted stock units awarded to each director was computed by dividing the cash value of the annual Board equity retainer by the average closing market price of the Company’s common stock over the 30-day period preceding the grant date. Generally, restricted stock units were awarded on the date of the Company’s annual meeting of shareholders and vested on April 15 of the following year. A director that ceased to be a Board member for any reason (other than death or disability, in which case the restricted stock units would vest immediately) before the vesting date would have been entitled to a pro-rated portion of his or her restricted stock units. Restricted stock units were settled in Company common stock. Restricted stock units did not have voting rights. Dividend equivalents were earned on restricted stock units as declared and paid and were reinvested in additional restricted stock units. Each director had the right to defer all or a portion of his or her restricted stock units upon vesting. Upon consummation of the Merger, (i) each of the directors was entitled to a distribution of their deferred equity account balances and (ii) unvested restricted stock units vested and each outstanding restricted stock unit was converted into a right to receive the Per-Share Merger Consideration.
To ensure that non-employee directors’ financial interests were aligned with the long-term interests of the Company and its shareholders, pursuant to our Corporate Governance Guidelines, each non-employee director was expected to hold a minimum of five times the amount of his or her annual equity Board compensation in Company common stock. Each non-employee director was given five years to acquire this level of stock ownership and individual circumstances impacting compliance with this policy were considered. The guidelines did not include any repercussions for not satisfying stock ownership levels. As of November 27, 2011, each non-employee director had satisfied these ownership guidelines. The average stock price of Company common stock during the prior 12 months was used to determine satisfaction of the guidelines.
The Company maintains the 2006 Deferred Compensation Plan for Non-Employee Directors, which generally enabled directors to defer all or a portion of their director cash fees earned in a particular year. If a director elected to defer any amount, such deferred amount was included as compensation for purposes of the Director Compensation Table, but not considered compensation for tax purposes in the year earned. Deferred compensation plan account balances accrue earnings based on investment options selected by the director, which included units of certain publicly traded mutual funds. DPL common stock was not an investment option under this plan. Upon consummation of the Merger, deferred compensation account balances commenced payment in cash, either in a lump sum or in annual installments over a period of up to five years as determined by the director’s deferral election form. There are sufficient assets in the master trust to provide for the payment of directors’ remaining deferred cash account balances.
In the normal course of business, DP&L enters into transactions with other subsidiaries of DPL. The following table provides a summary of these transactions for the periods presented: All material intercompany accounts and transactions are eliminated in DPL’s consolidated financial statements.
Years ended December 31, | ||||||||||||
2011 | 2010 | 2009 | ||||||||||
($ in millions) | ||||||||||||
DP&L Revenues: | ||||||||||||
Sales to DPLER(a) | 327.0 | 238.5 | 64.8 | |||||||||
DP&L Operation & Maintenance Expenses: | ||||||||||||
Premiums paid for insurance services provided by MVIC(b) | (3.1 | ) | (3.3 | ) | (3.4 | ) | ||||||
Expense recoveries for services provided to DPLER(c) | 4.6 | 5.8 | 1.5 |
(a) | DP&L sells power to DPLER to satisfy the electric requirements of DPLER’s retail customers. The revenue dollars associated with sales to DPLER are recorded as wholesale revenues in DP&L’s Financial Statements. The increase in DP&L’s sales to DPLER during the year ended December 31, 2011, compared to the year ended December 31, 2010 is primarily due to customers electing to switch their generation service from DP&L to DPLER. DP&L did not sell any physical power to MC Squared during either of these periods. |
(b) | MVIC, a wholly-owned captive insurance subsidiary of DPL, provides insurance coverage to DP&L and other DPL subsidiaries for workers’ compensation, general liability, property damages and directors’ and officers’ liability. These amounts represent insurance premiums paid by DP&L to MVIC. |
(c) | In the normal course of business DP&L incurs and records expenses on behalf of DPLER. Such expenses include but are not limited to employee-related expenses, accounting, information technology, payroll, legal and other administration expenses. DP&L subsequently charges these expenses to DPLER at DP&L’s cost and credits the expense in which they were initially recorded. |
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
($ in millions) | ||||||||||||||||
DP&L Revenues: | ||||||||||||||||
Sales to DPLER(a) | 86.7 | 81.0 | 169.7 | 156.1 | ||||||||||||
Sales to MC Squared | 0.3 | ¾ | 0.3 | ¾ | ||||||||||||
DP&L Operation & Maintenance Expenses: | ||||||||||||||||
Premiums paid for insurance services provided by MVIC(b) | (0.6 | ) | (0.8 | ) | (1.3 | ) | (1.6 | ) | ||||||||
Expense recoveries for services provided to DPLER(c) | 0.6 | 0.8 | 1.5 | 1.7 |
(a) | DP&L sells power to DPLER to satisfy the electric requirements of DPLER’s retail customers. The revenue dollars associated with sales to DPLER are recorded as wholesale revenues in DP&L’s Financial Statements. The increase in DP&L’s sales to DPLER during the three and six months ended June 30, 2012, compared to the three and six months ended June 30, 2011, is primarily due to customers electing to switch their generation service from DP&L to DPLER. |
(b) | MVIC, a wholly owned captive insurance subsidiary of DPL, provides insurance coverage to DP&L and other DPL subsidiaries for workers’ compensation, general liability, property damages and directors’ and officers’ liability. These amounts represent insurance premiums paid by DP&L to MVIC. |
(c) | In the normal course of business DP&L incurs and records expenses on behalf of DPLER. Such expenses include but are not limited to employee-related expenses, accounting, information technology, payroll, legal and |
other administration expenses. DP&L subsequently charges these expenses to DPLER at DP&L’s cost and credits the expense in which they were initially recorded.
Related Person Transactions
We have a written policy with respect to the review, approval and ratification of “related person transactions.” This policy applies to any transaction, arrangement or relationship (including any indebtedness or guarantee of indebtedness) or any series of similar transactions, arrangements or relationships in which (i) the aggregate amount involved will or may be expected to exceed $75,000 in any fiscal year; (ii) we are a participant and (iii) any “related person” (defined as a director, director nominee, an executive officer, someone who owns more than 5% of our common shares, or an immediate family member of any of the foregoing persons, with certain exceptions) has or will have a direct or indirect interest. Our governance counsel will determine whether a transaction meets the definition of a related person transaction that will require review by the Board of Directors. The Board of Directors will review all related person transactions referred to it and, based on the relevant facts and circumstances, will decide whether or not to approve such transactions. Only those transactions that are in, or are not inconsistent with, the best interests of the Company and its shareholders will be approved. If we become aware of an existing related person transaction that was not approved under this policy, the matter will be referred to the Board of Directors and it will evaluate all options available, including ratification, amendment or termination of the transaction.
We have determined that, under the policy, the following types of transactions will be deemed to be pre-approved: (i) employment of an executive officer if the related compensation is required to be reported in our public filings; (ii) employment of an executive officer if he or she is not an immediate family member of another executive officer or director of ours, the related compensation would have been reported in our public filings if he or she was a “named executive officer” and our Board of Directors approved such compensation; (iii) compensation paid to a director if the compensation is required to be reported in our public filings; (iv) any transaction where the related person’s interest arises solely from the ownership of our common stock and all holders of our common stock received the same benefit on a pro-rated basis; (v) any transaction involving competitive bids; (vi) any transaction in which the rates or charges incurred are subject to governmental regulation and (vii) any transaction involving bank depository of funds, transfer agent, registrar, trustee under a trust indenture or similar services.
The Company is not aware of any transaction or series of transactions involving any of our directors or executive officers, or any immediate family member (as described in Item 404 of Regulation S-K under the Exchange Act) of such director or executive officer, that is required to be disclosed pursuant to Item 404 of Regulation S-K.
In this Description of the Notes, “DPL,” the “Company,” “we,” “us,” and “our” refer only to DPL Inc., and any successor obligor on the notes, and not to any of its subsidiaries. There will be no recourse against AES with respect to the notes. You can find the definitions of certain terms used in this description under “—Certain Definitions.”
We will issue the notes under an indenture between us and Wells Fargo Bank, N.A., as trustee. The terms of the notes include those stated in the indenture and those made part of the indenture by reference to the Trust Indenture Act of 1939 (the “Trust Indenture Act”).
The following is a summary of the material provisions of the indenture. Because this is a summary, it may not contain all the information that is important to you. You should read the indenture in its entirety. Copies of the indenture are available as described under “Where You Can Find More Information.”
Basic Terms of Notes
The notes
· | are the senior unsecured obligations of DPL; |
· | rank equally with the existing and future unsubordinated and unsecured obligations of DPL; and are structurally subordinated to obligations of the subsidiaries of DPL; |
· | are effectively subordinated to any secured senior obligations of DPL, to the extent of the value of the collateral securing such obligations; |
· | mature on October 15, 2016 (the “New 2016 Notes”) and October 15, 2021 (the “New 2021 Notes” and together with the New 2016 Notes, the “notes”); |
· | with respect to the New 2016 Notes, are issued in an original aggregate principal amount of $450 million; |
· | with respect to the New 2021 Notes, are issued in an original aggregate principal amount of $800 million; |
· | with respect to the New 2016 Notes, bear interest commencing the date of issue at 6.50%, payable semiannually on each April 15 and October 15, commencing October 15, 2012, to holders of record on the April 1 or October 1 immediately preceding the interest payment date; and |
· | with respect to the New 2021 Notes, bear interest commencing the date of issue at 7.25%, payable semiannually on each April 15 and October 15, commencing October 15, 2012, to holders of record on the April 1 or October 1 immediately preceding the interest payment date. |
· | Interest will be computed on the basis of a 360-day year of twelve 30-day months. |
DPL is a holding company, and DPL’s rights and the rights of its creditors, including holders of the notes, in respect of claims on the assets of each of DPL’s subsidiaries, upon any liquidation or administration are structurally subordinated to, and therefore will be subject to the prior claims of, each such subsidiary’s preferred stockholders and creditors (including trade creditors of and holders of debt issued by such subsidiary).
At June 30, 2012, DPL’s direct and indirect subsidiaries had total long-term debt, current liabilities and preferred stock of approximately $1,203.5 million, all of which would be effectively senior to the notes.
At June 30, 2012, DPL had, on an unconsolidated basis, approximately $1,694.7 million of senior unsecured debt, and no secured or subordinated debt outstanding. At June 30, 2012, DPL had, on a consolidated basis, approximately $1,713.2 million of senior unsecured debt, $906.4 million of secured debt and no subordinated debt outstanding.
Our ability to pay interest on the notes of each series will be dependent upon the receipt of dividends and other distributions from our direct and indirect subsidiaries, including The Dayton Power and Light Company (“DP&L”)
in particular. The availability of distributions from our subsidiaries is subject to the satisfaction of various covenants and conditions contained in the applicable subsidiaries’ existing and future financing documents, organizational documents and regulatory stipulations.
The indenture does not limit the amount of debt securities we may issue under the indenture and provides that debt securities may be issued from time to time in one or more series. We may from time to time, without notice to or the consent of the holders of the notes of a series, create and issue additional debt securities (“Additional Notes”) under the indenture governing the notes having the same terms as, and ranking equally with, the notes of such series in all respects (except for the offering price and issue date). Any Additional Notes of any series, together with the notes of the applicable series offered hereby, will constitute a single series of notes under the indenture, and will be treated as a single class for all purposes thereunder, including voting under the indenture.
Optional Redemption
The New 2016 Notes will be redeemable prior to September 15, 2016 (one month prior to the maturity date) and the New 2021 Notes will be redeemable prior to July 15, 2021 (three months prior to the maturity date), in each case, at any time in whole or from time to time in part, at our option at a redemption price equal to the greater of:
(1) | 100% of the principal amount of the notes of that series being redeemed; or |
(2) | the sum of the present values of the remaining scheduled payments of principal of and interest on the notes of that series being redeemed discounted to the date of redemption on a semiannual basis (assuming a 360-day year consisting of twelve 30-day months) at the Treasury Rate (as defined herein) plus 50.0 basis points with respect to the New 2016 Notes and 50.0 basis points with respect to the New 2021 Notes; |
plus, for (1) or (2) above, whichever is applicable, accrued interest on such notes of that series to the date of redemption.
With respect to the New 2016 Notes, at any time on or after September 15, 2016 and with respect to the New 2021 Notes, at any time on or after July 15, 2021, the notes of that series will be redeemable in whole or in part, at our option, at a redemption price equal to 100% of the principal amount of the notes of that series to be redeemed plus accrued and unpaid interest on the notes to be redeemed to the date of redemption.
Definitions
“Comparable Treasury Issue” means the United States Treasury security selected by the Quotation Agent as having a maturity comparable to the remaining term (as measured from the date of redemption) of the notes of that series to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of the notes of that series.
“Comparable Treasury Price” means, with respect to any redemption date, (i) the average of five Reference Treasury Dealer Quotations for such redemption date, after excluding the highest and lowest such Reference Treasury Dealer Quotations, or (ii) if the Company obtains fewer than five such Reference Treasury Dealer Quotations, the average of all such quotations.
“Quotation Agent” means any Reference Treasury Dealer appointed by us.
“Reference Treasury Dealer” means (i) each of Merrill Lynch, Pierce, Fenner & Smith Incorporated, Barclays Capital Inc., J.P. Morgan Securities LLC (or their respective affiliates that are Primary Treasury Dealers) and their respective successors; provided, however, that if any of the foregoing shall cease to be a primary U.S. Government securities dealer in New York City (a “Primary Treasury Dealer”), we will substitute therefor another Primary Treasury Dealer, and (ii) any other Primary Treasury Dealers selected by us.
“Reference Treasury Dealer Quotations” means, with respect to each Reference Treasury Dealer and any redemption date, the average, as determined by the trustee, of the bid and asked prices for the Comparable Treasury
Issue (expressed in each case as a percentage of its principal amount) quoted in writing to the trustee by such Reference Treasury Dealer at 5:00 p.m., New York City time, on the third business day preceding such redemption date.
“Treasury Rate” means, with respect to any redemption date, the rate per annum equal to the semi annual equivalent yield to maturity of the Comparable Treasury Issue, assuming a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for such redemption date.
The redemption price will be calculated by the Quotation Agent and we, the trustee and any paying agent for the notes of that series to be redeemed will be entitled to rely on such calculation.
Notice of redemption must be given not less than 30 days nor more than 60 days prior to the date of redemption. If fewer than all the notes of a series are to be redeemed, selection of notes of that series for redemption will be made by the trustee in any manner the trustee deems fair and appropriate.
Unless we default in payment of the redemption price from and after the redemption date, the notes of a series or portions of them called for redemption will cease to bear interest, and the holders of the notes of that series will have no right in respect to such notes except the right to receive the redemption price for them.
It shall be the Company’s sole obligation to calculate the present value of the payments in connection with a redemption and the trustee shall have no obligation to calculate or verify any such payment amounts.
No Mandatory Redemption or Sinking Fund
There will be no mandatory redemption or sinking fund payments for the notes.
Repurchase at the Option of Holders
If a Change of Control Triggering Event (as defined herein) occurs, unless we have exercised our right to redeem the notes as described above, holders of the notes will have the right to require us to repurchase all or any part (no note of a principal amount of $2,000 or less will be repurchased in part) of their notes pursuant to the offer described below (the “Change of Control Offer”) on the terms set forth in the notes. In the Change of Control Offer, we will be required to offer payment in cash equal to 101% of the aggregate principal amount of notes repurchased plus accrued and unpaid interest, if any, on the notes repurchased, to the date of repurchase (the “Change of Control Payment”). Within 30 days following any Change of Control Triggering Event, we will be required to send a notice to holders of notes describing the transaction or transactions that constitute the Change of Control Triggering Event and offering to repurchase the notes on the date specified in the notice, which date will be no earlier than 30 days and no later than 60 days from the date such notice is mailed (the “Change of Control Payment Date”), pursuant to the procedures required by the notes and described in such notice. We must comply with the requirements of Rule 14e-1 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with the repurchase of the notes as a result of a Change of Control Triggering Event. To the extent that the provisions of any securities laws or regulations conflict with the Change of Control provisions of the notes, we will be required to comply with the applicable securities laws and regulations and will not be deemed to have breached our obligations under the Change of Control provisions of the notes by virtue of such conflicts.
On the Change of Control Payment Date, we will be required, to the extent lawful, to:
· | accept for payment all notes or portions of notes properly tendered pursuant to the Change of Control Offer; |
· | deposit with the paying agent, which shall initially be the trustee, an amount equal to the Change of Control Payment in respect of all notes or portions of notes properly tendered; and |
· | deliver or cause to be delivered to the trustee the notes properly accepted. |
The definition of Change of Control (defined herein) includes a phrase relating to the direct or indirect sale, lease, transfer, conveyance or other disposition of “all or substantially all” of the properties or assets of us and our subsidiaries taken as a whole. Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a holder of notes to require us to repurchase its notes as a result of a sale, lease, transfer, conveyance or other disposition of less than all of the assets of us and our subsidiaries taken as a whole to another person may be uncertain.
For purposes of the foregoing discussion of a repurchase at the option of holders, the following definitions are applicable:
“Change of Control” means the occurrence of any of the following: (1) the direct or indirect sale, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of the properties or assets of the Company and its subsidiaries taken as a whole to any person (as such term is used in Section 13(d) of the Exchange Act) other than the Company or one of its subsidiaries; (2) the consummation of any transaction (including, without limitation, any merger or consolidation), the result of which is that any person (as such term is used in Section 13(d) of the Exchange Act) other than a Permitted Holder (as defined herein) becomes the beneficial owner, directly or indirectly, of more than 50% of the then outstanding number of shares of the Company’s Voting Stock; or (3) the first day on which a majority of the members of the Company’s Board of Directors are not Continuing Directors of the Company.
“Change of Control Triggering Event” means the occurrence of a Rating Event and a Change of Control.
“Continuing Directors” means, as of any date of determination, any member of the applicable Board of Directors who (1) was a member of such Board of Directors on the date of the issuance of the notes; or (2) was nominated for election or elected to such Board of Directors with the approval of a majority of the Continuing Directors who were members of such Board of Directors at the time of such nomination or election (either by vote of the Board of Directors or by approval of the stockholders if applicable, after receipt of a proxy statement in which such member was named as a nominee for election as a director, without objection to such nomination).
“Permitted Holder” means, at any time, AES and its affiliates. In addition, any person or group whose acquisition of beneficial ownership constitutes a Change of Control in respect of which a Change of Control Offer is made in accordance with the requirements of the indenture will thereafter, together with its affiliates, constitute an additional Permitted Holder.
“Rating Agencies” means, with respect to any series of notes, (a) each of Fitch, Moody’s and S&P, and (b) if any of Fitch, Moody’s or S&P ceases to rate the notes or fails to make a rating of the notes publicly available for reasons outside of our control, a “nationally recognized statistical rating organization” (within the meaning of Rule 15c3-1(c)(2)(vi)(F) under the Exchange Act) selected by us as a replacement Rating Agency for a former Rating Agency.
“Rating Event” means the rating on the notes of such series is lowered by two of the three Rating Agencies on any day within the period commencing on the earlier of (a) the occurrence of a Change of Control and (b) public notice of the occurrence of a Change of Control or our intention to effect a Change of Control and ending 60 days following the consummation of such Change of Control (which 60-day period will be extended so long as the rating of the notes is under publicly announced consideration for a possible downgrade by any of the Rating Agencies).
“Voting Stock” of any specified person means the capital stock of such person that is at the time entitled to vote generally in the election of the Board of Directors of such person.
It shall be the Company’s sole obligation to determine if a Rating Event has occurred and the trustee shall have no obligation to determine or verify if such an event has occurred.
Ranking
Structural Subordination. DPL is a holding company. Substantially all of DPL’s operations are conducted through its subsidiaries. Claims of creditors of DPL’s subsidiaries, including trade creditors, secured creditors and creditors holding debt and guarantees issued by those subsidiaries, and claims of preferred and minority
stockholders (if any) of those subsidiaries generally will have priority with respect to the assets and earnings of those subsidiaries over the claims of creditors of DPL, including holders of the notes. The notes will be effectively subordinated to creditors (including trade creditors) and preferred and minority stockholders (if any) of DPL’s subsidiaries.
At June 30, 2012, DPL’s direct and indirect subsidiaries had total long-term debt, current liabilities and preferred stock of approximately $1,230.5 million, all of which would be effectively senior to the notes. Moreover, the indenture does not impose any limitation on the incurrence by subsidiaries of DPL of additional liabilities or the issuance of additional preferred stock or minority interests.
The notes will be the senior unsecured obligations of DPL and will be effectively subordinated to any secured senior obligations of DPL, to the extent of the value of the collateral securing such obligations. The notes will rank equally with the existing and future unsubordinated and unsecured obligations of DPL and will be structurally subordinated to obligations of the subsidiaries of DPL.
Moreover, as a holding company, DPL owns assets primarily through its ownership interests in its subsidiaries. None of its subsidiaries is obligated under the notes and none of its subsidiaries will guarantee the notes. DPL’s principal asset is its ownership interest in DP&L. DP&L is a regulated public utility, and is subject to regulation at both the state and federal level. At the state level, it is subject to regulation by the PUCO. At the federal level, it is subject to regulation by FERC. See “Business–Regulatory Matters Related to Air Quality.” Regulation by the PUCO and FERC includes regulation with respect to the change of control, transfer or ownership of utility property. Accordingly, if the trustee under the indenture or the holders of the notes institute proceedings against us with respect to the notes, the remedies available to them may be limited and may be subject to the approval by the PUCO and FERC.
Covenants
Except as otherwise set forth under “—Defeasance and Discharge” below, for so long as any notes remain outstanding or any amount remains unpaid on any of the notes, we will comply with the terms of the covenants set forth below.
Payment of Principal and Interest
We will duly and punctually pay the principal of and interest on the notes in accordance with the terms of the notes and the indenture.
Merger, Consolidation, Sale, Lease or Conveyance
The indenture provides that we will not (i)(a) consolidate with or merge with or into any other person, or permit any person to merge into or consolidate with us, or convey, transfer or lease our consolidated properties and assets substantially as an entirety (in one transaction or in a series of related transactions), (b) convey, transfer or lease our consolidated electric transmission and distribution assets and operations substantially as an entirety (in one transaction or in a series of related transactions), or (c) convey, transfer or lease all or substantially all of our consolidated electric generation assets and operations (in one transaction or a series of transactions), to any person or (ii) permit any of our subsidiaries to enter into any such transaction or series of transactions if it would result in the disposition of (x) our consolidated properties and assets substantially as an entirety, (y) our consolidated electric transmission and distribution assets and operations substantially as an entirety or (z) all or substantially all of our consolidated electric generation assets and operations unless, in each case:
· | we will be the surviving entity; or |
· | the successor corporation or person that acquires all or substantially all of our assets: |
· | will be an entity organized under the laws of the United States of America, one of its States or the District of Columbia; and |
· | expressly assumes by supplemental indenture our obligations under the notes and the indenture, provided, however, that in the event following a conveyance, transfer or lease of our consolidated properties and assets substantially as an entirety or a conveyance, transfer or lease of all or substantially all of our consolidated electric generation assets and operations, we continue to own, directly or indirectly, our consolidated electric transmission and distribution assets and operations that we held immediately preceding such conveyance, transfer or lease substantially as an entirety, the notes and the indenture shall remain the obligations of us and shall not be assumed by the surviving person; and, |
· | immediately after the merger, consolidation, sale, lease or conveyance, we, that person or the surviving entity will not be in default under the indenture. |
In addition to the indenture limitations, regulatory approval would be required for such transactions.
Limitations on Liens
Neither we nor any Significant Subsidiary (as defined herein) may issue, assume or guarantee any Indebtedness secured by a Lien upon any property or assets (other than any cash or cash equivalents) of us or such Significant Subsidiary (including, for the avoidance of doubt, any common stock of DP&L), as applicable, without effectively providing that the outstanding notes (together with, if we so determine, any other indebtedness or obligation then existing or thereafter created ranking equally with the notes) will be secured equally and ratably with (or prior to) such Indebtedness so long as such Indebtedness is so secured.
The foregoing limitation on Liens will not, however, apply to:
(1) Liens in existence on the date of original issue of the notes;
(2) any Lien created or arising over any property which is acquired, constructed or created by us or any of our Significant Subsidiaries, but only if:
(a) such Lien secures only principal amounts (not exceeding the cost of such acquisition, construction or creation) raised for the purposes of such acquisition, construction or creation, together with any costs, expenses, interest and fees incurred in relation to that property or a guarantee given in respect of that property;
(b) such Lien is created or arises on or before 180 days after the completion of such acquisition, construction or creation; and
(c) such Lien is confined solely to the property so acquired, constructed or created;
(3) (a) rights of financial institutions to offset credit balances in connection with the operation of cash management programs established for our benefit and/or a Significant Subsidiary or in connection with the issuance of letters of credit for our benefit and/or a Significant Subsidiary;
(b) any Lien on accounts receivable securing our Indebtedness and/or a Significant Subsidiary incurred in connection with the financing of such accounts receivable;
(c) any Lien incurred or deposits made in the ordinary course of business, including, but not limited to, (1) any mechanic’s, materialmen’s, carrier’s, workmen’s, vendors’ and other like Liens and (2) any Liens securing amounts in connection with workers’ compensation, unemployment insurance and other types of social security;
(d) any Lien upon specific items of inventory or other goods of us and/or a Significant Subsidiary and the proceeds thereof securing obligations of us and/or a Significant Subsidiary in respect of bankers’ acceptances issued or created for the account of such person to facilitate the purchase, shipment or storage of such inventory or other goods;
(e) any Lien incurred or deposits made securing the performance of tenders, bids, leases, trade contracts (other than for borrowed money), statutory obligations, surety bonds, appeal bonds, government contracts, performance bonds, return-of-money bonds, letters of credit not securing borrowings and other obligations of like nature incurred in the ordinary course of business;
(f) any Lien created by us or a Significant Subsidiary under or in connection with or arising out of a Currency, Interest Rate or Commodity Agreement (as defined herein) or any transactions or arrangements entered into in connection with the hedging or management of risks relating to the electricity or natural gas distribution industry, including a right of set off or right over a margin call account or any form of cash or cash collateral or any similar arrangement for obligations incurred in respect of Currency, Interest Rate or Commodity Agreements;
(g) any Lien arising out of title retention or like provisions in connection with the purchase of goods and equipment in the ordinary course of business; and
(h) any Lien securing reimbursement obligations under letters of credit, guaranties and other forms of credit enhancement given in connection with the purchase of goods and equipment in the ordinary course of business;
(4) Liens in favor of us or a subsidiary of ours;
(5) (a) Liens on any property or assets acquired from an entity which is merged with or into us or a Significant Subsidiary or any Liens on the property or assets of any entity existing at the time such entity becomes a subsidiary of ours and, in either case, is not created in anticipation of the transaction, unless the Lien was created to secure or provide for the payment of any part of the purchase price of that entity;
(b) any Lien on any property or assets existing at the time of its acquisition and which is not created in anticipation of such acquisition, unless the Lien was created to secure or provide for the payment of any part of the purchase price of such property or assets; and
(c) any Lien created or outstanding on or over any asset of any entity which becomes a Significant Subsidiary on or after the date of the issuance of the notes, where the Lien is created prior to the date on which that entity becomes a Significant Subsidiary;
(6) (a) Liens required by any contract, statute or regulation in order to permit us or a Significant Subsidiary to perform any contract or subcontract made by it with or at the request of a governmental entity or any governmental department, agency or instrumentality, or to secure partial, progress, advance or any other payments by us or a Significant Subsidiary to such governmental unit under the provisions of any contract, statute or regulation;
(b) any Lien securing industrial revenue, development, pollution control, solid waste disposal or similar bonds issued by or for our benefit or a Significant Subsidiary, provided that such industrial revenue, development, pollution control or similar bonds do not provide recourse generally to us and/or such Significant Subsidiary; and
(c) any Lien securing taxes or assessments or other applicable governmental charges or levies;
(7) any Lien which arises under any order of attachment, restraint or similar legal process arising in connection with court proceedings and any Lien which secures the reimbursement obligation for any bond obtained in connection with an appeal taken in any court proceeding, so long as the execution or other enforcement of such Lien arising under such legal process is effectively stayed and the claims secured by that Lien are being contested in good faith and, if appropriate, by appropriate legal proceedings, and any Lien in favor of a plaintiff or defendant in any action before a court or tribunal as security for costs and/or expenses;
(8) any extension, renewal or replacement (or successive extensions, renewals or replacements), as a whole or in part, of any Liens referred to in the foregoing clauses, for amounts not exceeding the principal amount of the Indebtedness secured by the Lien so extended, renewed or replaced, provided that such extension, renewal or replacement Lien is limited to all or a part of the same property or assets that were covered by the Lien extended, renewed or replaced (plus improvements on such property or assets);
(9) any Lien created in connection with Project Finance Debt (as defined herein);
(10) any Lien created by DP&L or its subsidiaries securing Indebtedness of DP&L or its subsidiaries;
(11) any Lien created in connection with the securitization of some or all of the assets of DP&L and the associated issuance of Indebtedness as authorized by applicable state or federal law in connection with the restructuring of jurisdictional electric or gas businesses;
(12) any Lien on stock created in connection with a mandatorily convertible or exchangeable stock or debt financing, provided that any such financing may not be secured by or otherwise involve the creation of a Lien on any capital stock of DP&L or any successor entity to DP&L; and
(13) any Lien under one or more credit facilities for Indebtedness in an aggregate principal amount outstanding at any time not to exceed 10% of Consolidated Net Assets.
Reports and Other Information
At any time that we are not subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act, or do not otherwise report on an annual and quarterly basis on forms provided for such annual and quarterly reporting pursuant to rules and regulations promulgated by the Securities and Exchange Commission, the indenture will require us to deliver (which may be accomplished through the posting on the internet) to the trustee and to holders of the notes, without cost to any holder:
(1) within 90 days after the end of each fiscal year, audited financial statements; and
(2) within 45 days after the end of each of the first three fiscal quarters of each fiscal year, quarterly unaudited financial statements.
Events of Default
An Event of Default with respect to the notes of any series is defined in the indenture as being:
(1) default for 30 days in the payment of any interest on the notes of that series;
(2) default in the payment of principal of or any premium on, the notes of that series at maturity, upon redemption, upon required purchase, upon acceleration or otherwise;
(3) default in the performance, or breach, of any covenant or obligation in the indenture and continuance of the default or breach for a period of 30 days after written notice specifying the default is given to us by the trustee or to us and the trustee by the holders of at least 25% in principal amount of the notes of that series;
(4) default in the payment of the principal of any bond, debenture, note or other evidence of indebtedness, in each case for money borrowed, issued by us, or in the payment of principal under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any Indebtedness for Borrowed Money, of us or any Significant Subsidiary if such Indebtedness for Borrowed Money is not Project Finance Debt and provides for recourse generally to us or any Significant Subsidiary, which default for payment of principal is in an aggregate principal amount exceeding $40 million when such indebtedness becomes due and payable (whether at maturity, upon redemption or acceleration or otherwise), if such default shall continue unremedied or unwaived for more than 30 business days and the time for payment of such amount has not been expressly extended (until such time as such payment default is remedied, cured or waived);
(5) a court having jurisdiction enters a decree or order for:
· | relief in respect of us or any of our Significant Subsidiaries in an involuntary case under any applicable bankruptcy, insolvency, or other similar law now or hereafter in effect; or |
· | appointment of a receiver, liquidator, assignee, custodian, trustee, sequestrator, or similar official of us or any of our Significant Subsidiaries or for all or substantially all of the property and assets of us or any of our Significant Subsidiaries; or |
· | the winding up or liquidation of our affairs or any of our Significant Subsidiaries; |
and, in either case, such decree or order remains unstayed and in effect for a period of 60 consecutive days; or
(6) we or any of our Significant Subsidiaries:
· | commences a voluntary case under any applicable bankruptcy, insolvency, or other similar law now or hereafter in effect, or consents to the entry of an order for relief in an involuntary case under any such law; |
· | consents to the appointment of or taking possession by a receiver, liquidator, assignee, custodian, trustee, sequestrator, or similar official of us or any of our Significant Subsidiaries or for all or substantially all of the property and assets of us or any of our Significant Subsidiaries; or |
· | effects any general assignment for the benefit of creditors. |
If an Event of Default (other than an Event of Default specified in clause (5) or (6) with respect to us) occurs with respect to the notes of a series and continues, then the trustee or the holders of at least 25% in aggregate principal amount of the notes of that series then outstanding may, by written notice to us, and the trustee at the request of at least 25% in principal amount of the notes of that series then outstanding will, declare the principal, premium, if any, and accrued interest on the outstanding notes of that series to be immediately due and payable. Upon a declaration of acceleration, the principal, premium, if any, and accrued interest shall be immediately due and payable.
If an Event of Default specified in clause (5) or (6) above occurs with respect to us, the principal, premium, if any, and accrued interest on the notes shall be immediately due and payable, without any declaration or other act on the part of the trustee or any holder.
The holders of at least a majority in principal amount of the notes of a series may, by written notice to us and to the trustee, waive all past defaults with respect to the notes of that series and rescind and annul a declaration of acceleration with respect to the notes of that series and its consequences if:
· | all existing Events of Default applicable to the notes other than the nonpayment of the principal, premium, if any, and interest on the notes that have become due solely by that declaration of acceleration, have been cured or waived; and |
· | the rescission would not conflict with any judgment or decree of a court of competent jurisdiction. |
No holder of the notes of a series will have any right to institute any proceeding, judicial or otherwise, with respect to the indenture, or for the appointment of a receiver or trustee, or for any other remedy under the indenture, unless:
· | such holder has previously given written notice to the trustee of a continuing Event of Default with respect to the notes of that series; |
· | the holders of not less than 25% in principal amount of the notes shall have made written request to a responsible officer of the trustee to institute proceedings in respect of such Event of Default in its own name as trustee; |
· | such holder or holders have offered the trustee indemnity satisfactory to the trustee against the costs, expenses and liabilities to be incurred in compliance with such request; |
· | the trustee, for 60 days after its receipt of such notice, request and offer of indemnity, has failed to institute any such proceeding; and |
· | no direction inconsistent with such written request has been given to the trustee during such 60-day period by the holders of a majority in principal amount of the outstanding notes of that series. |
However, these limitations do not apply to the right of any holder of a note to receive payment of the principal, premium, if any, or interest on, that note or to bring suit for the enforcement of any payment, on or after the due date expressed in the notes, which right shall not be impaired or affected without the consent of the holder.
The indenture requires that certain of our officers certify, on or before a date not more than 120 days after the end of each fiscal year, that to the best of those officers’ knowledge, we have fulfilled all our obligations under the indenture. We are also obligated to notify the trustee of any default or defaults in the performance of any covenants or agreements under the indenture provided, however, that a failure by us to deliver such notice of a default shall not constitute a default under the indenture, if we have remedied such default within any applicable cure period.
No Liability of Directors, Officers, Employees, Incorporators and Stockholders
No director, officer, employee, incorporator, member or stockholder of us, as such, will have any liability for any of our obligations under the notes or the indenture or for any claim based on, in respect of, or by reason of, such obligations. Each holder of notes by accepting a note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the notes. This waiver may not be effective to waive liabilities under the federal securities laws and it is the view of the Securities and Exchange Commission that such a waiver is against public policy.
Amendments and Waivers
Amendments Without Consent of Holders. We and the trustee may amend or supplement the indenture or the notes without notice to or the consent of any holder:
(1) to cure any ambiguity, defect or inconsistency in the indenture or the notes;
(2) to comply with “—Merger, Consolidation, Sale, Lease or Conveyance;”
(3) to comply with any requirements of the Securities and Exchange Commission in connection with the qualification of the indenture under the Trust Indenture Act;
(4) to evidence and provide for the acceptance of appointment hereunder by a successor trustee;
(5) to provide for any guarantee of the notes, to secure the notes or to confirm and evidence the release, termination or discharge of any guarantee of or lien securing the notes when such release, termination or discharge is permitted by the indenture;
(6) to provide for or confirm the issuance of additional notes; or
(7) to make any other change that does not materially and adversely affect the rights of any holder.
Amendments With Consent of Holders. (a) Except as otherwise provided in “—Events of Default” or paragraph (b), we and the trustee may amend the indenture with respect to the notes of a series with the written consent of the holders of a majority in principal amount of the outstanding notes of that series and the holders of a majority in principal amount of the outstanding notes of that series may waive future compliance by us with any provision of the indenture with respect to the notes of that series.
(b) Notwithstanding the provisions of paragraph (a), without the consent of each holder of notes of a series, an amendment or waiver may not:
(1) reduce the principal amount of or change the stated maturity of any installment of principal of the notes of that series;
(2) reduce the rate of or change the stated maturity of any interest payment on the notes of that series;
(3) reduce the amount payable upon the redemption of the notes of that series, in respect of an optional redemption, change the times at which the notes of that series may be redeemed or, once notice of redemption has been given, the time at which they must thereupon be redeemed;
(4) make the notes of that series payable in money other than that stated in such notes,
(5) impair the right of any holder of notes of that series to receive any principal payment or interest payment on such holder’s notes, on or after the stated maturity thereof, or to institute suit for the enforcement of any such payment,
(6) make any change in the percentage of the principal amount of the notes of that series required for amendments or waivers; or
(7) modify or change any provision of the indenture affecting the ranking of the notes of that series in a manner adverse to the holders of the notes of that series.
It is not necessary for holders to approve the particular form of any proposed amendment, supplement or waiver, but is sufficient if their consent approves the substance thereof.
Neither we nor any of our Subsidiaries or affiliates may, directly or indirectly, pay or cause to be paid any consideration, whether by way of interest, fee or otherwise, to any holder for or as an inducement to any consent, waiver or amendment of any of the terms or provisions of the indenture or the notes of a series unless such consideration is offered to be paid or agreed to be paid to all holders of the notes of that series that consent, waive or agree to amend such term or provision within the time period set forth in the solicitation documents relating to the consent, waiver or amendment.
Defeasance and Discharge
The indenture provides that we are deemed to have paid and will be discharged from all obligations in respect of the notes of a series on the 123rd day after the deposit referred to below has been made, and that the provisions of the indenture will no longer be in effect with respect to the notes of that series (except for, among other matters, certain obligations to register the transfer or exchange of the notes of that series, to replace stolen, lost or mutilated notes of that series, to maintain paying agencies and to hold monies for payment in trust) if, among other things,
(1) we have deposited with the trustee, in trust, money and/or U.S. Government Obligations (as defined herein) that, through the payment of interest and principal in respect thereof, will provide money in an amount sufficient to pay the principal, premium, if any, and accrued interest on the notes of that series, on the due date thereof or earlier redemption (irrevocably provided for under arrangements satisfactory to the trustee), as the case may be, in accordance with the terms of the indenture;
(2) we have delivered to the trustee either:
· | an opinion of counsel to the effect that holders of notes of that series will not recognize income, gain or loss for federal income tax purposes as a result of the exercise of our option under this “Defeasance and Discharge” provision and will be subject to federal income tax on the same amount and in the same manner and at the same times as would have been the case if the deposit, defeasance and discharge had not occurred, which opinion of counsel must be based upon a ruling of the Internal Revenue Service to the same effect unless there has been a change in applicable federal income tax law or related treasury regulations after the date of the indenture, or |
· | a ruling directed to the trustee received from the Internal Revenue Service to the same effect as the aforementioned opinion of counsel; |
(3) we have delivered to the trustee an opinion of counsel to the effect that the creation of the defeasance trust does not violate the Investment Company Act of 1940 and after the passage of 123 days following the deposit, the trust fund will not be subject to the effect of Section 547 of the U.S. Bankruptcy Code or Section 15 of the New York Debtor and Creditor Law,
(4) immediately after giving effect to that deposit on a pro forma basis, no Event of Default has occurred and is continuing on the date of the deposit or during the period ending on the 123rd day after the date of the deposit, and the deposit will not result in a breach or violation of, or constitute a default under, any other agreement or instrument to which we are a party or by which we are bound, and
(5) if at that time any notes of that series are listed on a national securities exchange, we have delivered to the trustee an opinion of counsel to the effect that the notes of that series will not be delisted as a result of a deposit, defeasance and discharge.
As more fully described in the indenture, the indenture also provides for defeasance of certain covenants.
Concerning the Trustee
Wells Fargo Bank, N.A., acts as the trustee under the indenture.
Except during the continuance of an Event of Default, the trustee need perform only those duties that are specifically set forth in the indenture and no others, and no implied covenants or obligations will be read into the indenture against the trustee. In case an Event of Default has occurred and is continuing, the trustee shall exercise those rights and powers vested in it by the indenture and use the same degree of care and skill in their exercise as a prudent person would exercise or use under the circumstances in the conduct of such person’s own affairs. No provision of the indenture will require the trustee to expend or risk its own funds or otherwise incur any financial liability in the performance of its duties or in the exercise of its rights or powers thereunder. The trustee shall be under no obligation to exercise any of the rights or powers vested in it by the indenture at the request or direction of any of the holders pursuant to the indenture, unless such holders shall have offered to the trustee security or indemnity satisfactory to the trustee against the costs, expenses and liabilities which might be incurred by it in compliance with such request or direction.
The indenture and provisions of the Trust Indenture Act incorporated by reference therein contain limitations on the rights of the trustee, should it become a creditor of us, to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise. The trustee is permitted to engage in other transactions with us and our affiliates; provided that if it acquires any conflicting interest it must either eliminate the conflict within 90 days, apply to the Securities and Exchange Commission for permission to continue or resign.
Form, Denomination and Registration of Notes
Except as set forth below, the notes will be issued in registered, global form in minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof. The notes will be issued at the closing of this offering only against payment in immediately available funds.
The Global Notes will be deposited upon issuance with the trustee as custodian for DTC and registered in the name of DTC or its nominee, in each case for credit to an account of a direct or indirect participant in DTC as described below. Global Notes may be transferred, in whole and not in part, only to another nominee of DTC or to a successor of DTC or its nominee. Beneficial interests in the Global Notes may be exchanged for Notes in certificated form. See “—Exchange of Global Notes for Certificated Notes.”
In addition, transfers of beneficial interests in the Global Notes will be subject to the applicable rules and procedures of DTC and its direct or indirect participants (including, if applicable, those of Euroclear and Clearstream), which may change from time to time.
Depository Procedures
The following description of the operations and procedures of DTC, Euroclear and Clearstream are provided solely as a matter of convenience. These operations and procedures are solely within the control of the respective settlement systems and are subject to changes by them. We and the trustee take no responsibility for these operations and procedures and urge investors to contact the system or their participants directly to discuss these matters.
DTC has advised us that DTC is a limited-purpose trust company created to hold securities for its participating organizations (collectively, the “Participants”) and to facilitate the clearance and settlement of transactions in those securities between Participants through electronic book-entry changes in accounts of its Participants. The Participants include securities brokers and dealers (including the initial purchasers), banks, trust companies, clearing corporations and certain other organizations. Access to DTC’s system is also available to other entities such as
banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a Participant, either directly or indirectly (collectively, the “Indirect Participants”). Persons who are not Participants may beneficially own securities held by or on behalf of DTC only through the Participants or the Indirect Participants. The ownership interests in, and transfers of ownership interests in, each security held by or on behalf of DTC are recorded on the records of the Participants and Indirect Participants. DTC has also advised us that, pursuant to procedures established by it:
(1) upon deposit of the Global Notes, DTC will credit the accounts of Participants designated by the initial purchasers with portions of the principal amount of the Global Notes; and
(2) ownership of these interests in the Global Notes will be shown on, and the transfer of ownership thereof will be effected only through, records maintained by DTC (with respect to the Participants) or by the Participants and the Indirect Participants (with respect to other owners of beneficial interest in the Global Notes).
All interests in a Global Note, including those held through Euroclear or Clearstream, may be subject to the procedures and requirements of DTC. Those interests held through Euroclear or Clearstream may also be subject to the procedures and requirements of such systems.
The laws of some states require that certain persons take physical delivery in definitive form of securities that they own. Consequently, the ability to transfer beneficial interests in a Global Note to such persons will be limited to that extent. Because DTC can act only on behalf of the Participants, which in turn act on behalf of the Indirect Participants, the ability of a person having beneficial interests in a Global Note to pledge such interests to persons that do not participate in the DTC system, or otherwise take actions in respect of such interests, may be affected by the lack of a physical certificate evidencing such interests.
Except as described below, owners of interests in the Global Notes will not have notes registered in their names, will not receive physical delivery of notes in certificated form and will not be considered the registered owners or “holders” thereof under the indenture for any purpose.
Payments in respect of the principal of, and interest and premium, if any, on a Global Note registered in the name of DTC or its nominee will be payable to DTC in its capacity as the registered holder under the indenture. Under the terms of the indenture, we and the trustee will treat the persons in whose names the notes, including the Global Notes, are registered as the owners thereof for the purpose of receiving payments and for all other purposes. Consequently, neither we, the trustee, nor any agent of ours or the trustee’s has or will have any responsibility or liability for:
(1) any aspect of DTC’s records or any Participant’s or Indirect Participant’s records relating to or payments made on account of beneficial ownership interest in the Global Notes or for maintaining, supervising or reviewing any of DTC’s records or any Participant’s or Indirect Participant’s records relating to the beneficial ownership interests in the Global Notes; or
(2) any other matter relating to the actions and practices of DTC or any of its Participants or Indirect Participants.
DTC has advised us that its current practice, upon receipt of any payment in respect of securities such as the notes (including principal and interest), is to credit the accounts of the relevant Participants with the payment on the payment date unless DTC has reason to believe it will not receive payment on such payment date. Each relevant Participant is credited with an amount proportionate to its beneficial ownership of an interest in the principal amount of the relevant security as shown on the records of DTC. Payments by the Participants and the Indirect Participants to the beneficial owners of the notes will be governed by standing instructions and customary practices and will be the responsibility of the Participants or the Indirect Participants and will not be the responsibility of DTC, the trustee or us. Neither we nor the trustee will be liable for any delay by DTC or any of its Participants in identifying the beneficial owners of the notes, and we and the trustee may conclusively rely on and will be protected in relying on instructions from DTC or its nominee for all purposes. Transfers between Participants in DTC will be effected in accordance with DTC’s procedures, and will be settled in same-day funds, and transfers between participants in Euroclear and Clearstream will be effected in accordance with their respective rules and operating procedures.
Subject to compliance with the transfer restrictions applicable to the notes described herein, crossmarket transfers between the Participants in DTC, on the one hand, and Euroclear or Clearstream participants, on the other hand, will be effected through DTC in accordance with DTC’s rules on behalf of Euroclear or Clearstream, as the case may be, by its respective depositary; however, such cross-market transactions will require delivery of instructions to Euroclear or Clearstream, as the case may be, by the counterparty in such system in accordance with the rules and procedures and within the established deadlines (Brussels time) of such system. Euroclear or Clearstream, as the case may be, will, if the transaction meets its settlement requirements, deliver instructions to its respective depositary to take action to effect final settlement on its behalf by delivering or receiving interests in the relevant Global Note in DTC, and making or receiving payment in accordance with normal procedures for same-day funds settlement applicable to DTC. Euroclear participants and Clearstream participants may not deliver instructions directly to the depositories for Euroclear or Clearstream.
DTC has advised us that it will take any action permitted to be taken by a holder of the notes only at the direction of one or more Participants to whose account DTC has credited the interests in the Global Notes and only in respect of such portion of the aggregate principal amount of the notes as to which such Participant or Participants has or have given such direction. However, if there is an Event of Default under the notes, DTC reserves the right to exchange the Global Notes for legended notes in certificated form, and to distribute such notes to its Participants.
Exchange of Global Notes for Certificated Notes
A Global Note is exchangeable for definitive notes in registered certificated form (“Certificated Notes”) if:
(1) DTC (a) notifies us that it is unwilling or unable to continue as depositary for the Global Notes or (b) has ceased to be a clearing agency registered under the Exchange Act, and in each case we fail to appoint a successor depositary within 90 days of that notice or becoming aware that DTC is no longer so registered or willing or able to act as a depositary;
(2) we determine not to have the Notes represented by a Global Note and provide written notice thereof to the trustee; or
(3) there shall have occurred and be continuing a Default or Event of Default with respect to the notes and DTC requests such exchange.
In all cases, certificated Notes delivered in exchange for any Global Note or beneficial interests in Global Notes will be in registered form, registered in the names, and issued in any approved denominations, requested by or on behalf of the depositary (in accordance with its customary procedures).
Governing Law
The indenture and the notes shall be governed by, and construed in accordance with, the laws of the State of New York.
Certain Definitions
Set forth below are certain defined terms used in the indenture. We refer you to the indenture for a full disclosure of all such terms, as well as any other capitalized terms used in this section of the prospectus for which no definition is provided.
“Capitalized Lease Obligations” means all lease obligations of us and our subsidiaries which, under GAAP, are or will be required to be capitalized, in each case taken at the amount of the lease obligation accounted for as indebtedness in conformity with those principles.
“Cash Equivalents” means:
(1) United States dollars and such local currencies held by the Company or any Significant Subsidiary from time to time in the ordinary course of business;
(2) securities issued or directly and fully guaranteed or insured by the United States government or any agency or instrumentality thereof (provided that the full faith and credit of the United States is pledged in support thereof), maturing, no later than September 30, 2012;
(3) investments in time or demand deposit accounts, certificates of deposit and money market deposits maturing no later than September 30, 2012 issued by a bank or trust company which is organized under the laws of the United States of America, any State thereof or any foreign country recognized by the United States, and which bank or trust company has capital, surplus and undivided profits aggregating in excess of $500,000,000 (or the foreign currency equivalent thereof) and has outstanding debt which is rated “A-2” or higher by Moody’s, “A” or higher by S&P or the equivalent rating by any other nationally recognized statistical rating organization (as defined in Section 3 under the Exchange Act) or any money-market fund sponsored by a registered broker dealer or mutual fund distributor; and
(4) repurchase obligations with a term of not more than seven days for underlying securities of the types described in clauses (2) and (3) above entered into with any financial institution meeting the qualifications specified in clause (3) above.
“Consolidated Net Assets” means the aggregate amount of assets (less reserves and other deductible items) after deducting current liabilities, as shown on the consolidated balance sheet of the Company and its subsidiaries contained in its latest audited financial statements and prepared in accordance with GAAP.
“Currency, Interest Rate or Commodity Agreements” means an agreement or transaction involving any currency, interest rate or energy price or volumetric swap, cap or collar arrangement, forward exchange transaction, option, warrant, forward rate agreement, futures contract or other derivative instrument of any kind for the hedging or management of foreign exchange, interest rate or energy price or volumetric risks, it being understood, for purposes of this definition, that the term “energy” will include, without limitation, coal, gas, oil and electricity.
“DTC” means The Depository Trust Company and its successors.
“Excluded Subsidiary” means any subsidiary of us:
(1) in respect of which neither we nor any subsidiary of ours (other than another Excluded Subsidiary) has undertaken any legal obligation to give any guarantee for the benefit of the holders of any Indebtedness for Borrowed Money (other than to another member of the Group) other than in respect of any statutory obligation and the subsidiaries of which are all Excluded Subsidiaries; and
(2) which has been designated as such by us by written notice to the trustee; provided that we may give written notice to the trustee at any time that any Excluded Subsidiary is no longer an Excluded Subsidiary whereupon it shall cease to be an Excluded Subsidiary.
“Fitch” means Fitch Ratings Ltd.
“GAAP” means generally accepted accounting principles in the United States as in effect from time to time.
“Group” means DPL and its subsidiaries and “member of the Group” shall be construed accordingly.
“Indebtedness” means, with respect to us or any of our subsidiaries at any date of determination (without duplication):
(1) all Indebtedness for Borrowed Money (excluding any credit which is available but undrawn);
(2) all obligations in respect of letters of credit (including reimbursement obligations with respect to letters of credit);
(3) all obligations to pay the deferred and unpaid purchase price of property or services, which purchase price is due more than six months after the date of placing such property in service or taking delivery and title to the property or the completion of such services, except trade payables;
(4) all Capitalized Lease Obligations;
(5) all indebtedness of other persons secured by a mortgage, charge, lien, pledge or other security interest on any asset of us or any of our subsidiaries, whether or not such indebtedness is assumed; provided that the amount of such Indebtedness must be the lesser of: (a) the fair market value of such asset at such date of determination and (b) the amount of the secured indebtedness;
(6) all indebtedness of other persons of the types specified in the preceding clauses (1) through (5), to the extent such indebtedness is guaranteed by us or any of our subsidiaries; and
(7) to the extent not otherwise included in this definition, net obligations under Currency, Interest Rate or Commodity Agreements.
The amount of Indebtedness at any date will be the outstanding balance at such date of all unconditional obligations as described above and, upon the occurrence of the contingency giving rise to the obligation, the maximum liability of any contingent obligations of the types specified in the preceding clauses (1) through (7) at such date; provided that the amount outstanding at any time of any Indebtedness issued with original issue discount is the face amount of such Indebtedness less the remaining unamortized portion of the original issue discount of such Indebtedness at such time as determined in conformity with GAAP.
“Indebtedness For Borrowed Money” means any indebtedness (whether being principal, premium, interest or other amounts) for:
· | money borrowed; |
· | payment obligations under or in respect of any trade acceptance or trade acceptance credit; or |
· | any notes, bonds, loan stock or other debt securities offered, issued or distributed whether by way of public offer, private placement, acquisition consideration or otherwise and whether issued for cash or in whole or in part for a consideration other than cash; |
· | provided, however, in each case, that such term will exclude: |
· | any indebtedness relating to any accounts receivable securitizations; |
· | any Indebtedness of the type permitted to be secured by Liens pursuant to clause (12) under the caption “–Limitations on Liens” described above; and |
· | any Preferred Securities which are issued and outstanding on the date of original issue of the notes or any extension, renewal or replacement (or successive extensions, renewals or replacements), as a whole or in part, of any such existing Preferred Securities, for amounts not exceeding the principal amount or liquidation preference of the Preferred Securities so extended, renewed or replaced. |
“Lien” means any mortgage, lien, pledge, security interest or other encumbrance; provided, however, that the term “Lien” does not mean any easements, rights-of-way, restrictions and other similar encumbrances and encumbrances consisting of zoning restrictions, leases, subleases, restrictions on the use of property or defects in title.
“Moody’s” means Moody’s Investors Service, Inc.
“Preferred Securities” means, without duplication, any trust preferred or preferred securities or related debt or guaranties of us or any of our subsidiaries.
“Project Finance Debt” means:
· | any Indebtedness to finance or refinance the ownership, acquisition, development, design, engineering, procurement, construction, servicing, management and/or operation of any project or asset which is incurred by an Excluded Subsidiary; and |
· | any Indebtedness to finance or refinance the ownership, acquisition, development, design, engineering, procurement, construction, servicing, management and/or operation of any project or asset in respect of |
which the person or persons to whom any such Indebtedness is or may be owed by the relevant borrower (whether or not a member of the Group) has or have no recourse whatsoever to any member of the Group (other than an Excluded Subsidiary) for the repayment of that Indebtedness other than: (i) recourse to such member of the Group for amounts limited to the cash flow or net cash flow (other than historic cash flow or historic net cash flow) from, or ownership interests or other investments in, such project or asset; and/or (ii) recourse to such member of the Group for the purpose only of enabling amounts to be claimed in respect of such Indebtedness in an enforcement of any encumbrance given by such member of the Group over such project or asset or the income, cash flow or other proceeds deriving from the project (or given by any shareholder or the like, or other investor in, the borrower or in the owner of such project or asset over its shares or the like in the capital of, or other investment in, the borrower or in the owner of such project or asset) to secure such Indebtedness, provided that the extent of such recourse to such member of the Group is limited solely to the amount of any recoveries made on any such enforcement; and/or (iii) recourse to such borrower generally, or directly or indirectly to a member of the Group, under any form of assurance, indemnity, undertaking or support, which recourse is limited to a claim for damages (other than liquidated damages and damages required to be calculated in a specified way) for breach of an obligation (not being a payment obligation or an obligation to procure payment by another or an indemnity in respect of a payment obligation, or any obligation to comply or to procure compliance by another with any financial ratios or other tests of financial condition) by the person against which such recourse is available.
“S&P” means Standard & Poor’s Rating Services, a division of The McGraw-Hill Companies, Inc.
“Significant Subsidiary” means, at any particular time, any subsidiary of ours whose gross assets or gross revenues (having regard to our direct and/or indirect beneficial interest in the shares, or the like, of that subsidiary) represent at least 25% of the consolidated gross assets or, as the case may be, consolidated gross revenues of us.
“Subsidiary” means, with respect to any person, any corporation, association, partnership, limited liability company or other business entity of which 50% or more of the total voting power of shares of capital stock or other interests (including partnership interests) entitled (without regard to the occurrence of any contingency) to vote in the election of directors, managers or trustees is at the time owned, directly or indirectly, by (1) such person, (2) such person and one or more subsidiaries of such person or (3) one or more subsidiaries of such person.
“U.S. Government Obligation” means any:
(1) security which is: (a) a direct obligation of the United States for the payment of which the full faith and credit of the United States is pledged or (b) an obligation of a person controlled or supervised by and acting as an agency or instrumentality of the United States the payment of which is unconditionally guaranteed as a full faith and credit obligation by the United States, which, in the case of clause (a) or (b), is not callable or redeemable at the option of the issuer of the obligation, and
(2) depositary receipt issued by a bank (as defined in the Securities Act) as custodian with respect to any security specified in clause (1) above and held by such bank for the account of the holder of such depositary receipt or with respect to any specific payment of principal of or interest on any such security held by any such bank, provided that (except as required by law) such custodian is not authorized to make any deduction from the amount payable to the holder of such depositary receipt from any amount received by the custodian in respect of the U.S. Government Obligation or the specific payment of interest on or principal of the U.S. Government Obligation evidenced by such depositary receipt.
General
We hereby offer to exchange a like principal amount of new notes for any or all outstanding old notes on the terms and subject to the conditions set forth in this prospectus and accompanying letter of transmittal. We often refer to this offer as the “exchange offer.” You may tender some or all of your outstanding old notes pursuant to this exchange offer. As of the date of this prospectus, $450,000,000 aggregate principal amount of the Old 2016 Notes and $800,000,000 aggregate principal amount of the Old 2021 Notes are outstanding. Our obligation to accept old notes for exchange pursuant to the exchange offer is subject to certain conditions set forth hereunder.
Purpose and Effect of the Exchange Offer
In connection with the offering of the old notes, which was consummated on October 3, 2011, we entered into a registration rights agreement with the initial purchasers of the old notes, under which we agreed:
(1) to file a registration statement on or prior to 365 days after the closing of the offering of the old securities with respect to an offer to exchange the old notes for a new issue of securities, with terms substantially the same as of the old notes but registered under the Securities Act;
(2) to use our best efforts to cause the registration statement to be declared effective by the SEC; and
(3) to use our best efforts to consummate the exchange offer and issue the new notes within 425 business days after the closing of the old notes offering.
The registration rights agreement provides that, if (a) we do not consummate the exchange offer registration on or prior to the date that is 425 days following the issuance of the old notes or (b) we have not caused to become effective a shelf registration statement by the 90th day after such obligation arises (which in no event, however, shall be earlier than the exchange offer closing deadline), the interest rate for the notes will increase by a rate of 0.50% per annum from the exchange offer closing deadline or the shelf effectiveness deadline, as applicable, until the exchange offer is completed, in the case of an exchange offer, or the shelf registration statement is declared effective. Once we complete this exchange offer, we will no longer be required to pay additional interest on the old notes.
The exchange offer is not being made to, nor will we accept tenders for exchange from, holders of old notes in any jurisdiction in which the exchange offer or acceptance of the exchange offer would violate the securities or blue sky laws of that jurisdiction. Furthermore, each holder of old notes that wishes to exchange their old notes for new notes in this exchange offer will be required to make certain representations as set forth herein.
Terms of the Exchange Offer; Period for Tendering Old Notes
This prospectus and the accompanying letter of transmittal contain the terms and conditions of the exchange offer. Upon the terms and subject to the conditions included in this prospectus and in the accompanying letter of transmittal, which together are the exchange offer, we will accept for exchange old notes which are properly tendered on or prior to the expiration date, unless you have previously withdrawn them.
· | When you tender to us old notes as provided below, our acceptance of the old notes will constitute a binding agreement between you and us upon the terms and subject to the conditions in this prospectus and in the accompanying letter of transmittal. |
· | For each $2,000 principal amount of old notes (and $1,000 principal amount of old notes in excess thereof) surrendered to us in the exchange offer, we will give you $2,000 principal amount of new notes (and $1,000 principal amount of new notes in excess thereof). Outstanding notes may only be tendered in denominations of $2,000 and integral multiples of $1,000 in excess thereof. |
· | We will keep the exchange offer open for not less than 20 business days, or longer if required by applicable law, after the date that we first mail notice of the exchange offer to the holders of the old notes. We are sending this prospectus, together with the letter of transmittal, on or about the date of this prospectus to all |
of the registered holders of old notes at their addresses listed in the trustee’s security register with respect to the old notes.
· | The exchange offer expires at 11:59 P.M., New York City time, on , 2012; provided, however, that we, in our sole discretion, may extend the period of time for which the exchange offer is open. The term “expiration date” means , 2012 or, if extended by us, the latest time and date to which the exchange offer is extended. |
· | As of the date of this prospectus, $450,000,000 aggregate principal amount of the Old 2016 Notes and $800,000,000 aggregate principal amount of the Old 2021 Notes was outstanding. The exchange offer is not conditioned upon any minimum principal amount of old notes being tendered. |
· | Our obligation to accept old notes for exchange in the exchange offer is subject to the conditions that we describe in the section called “Conditions to the Exchange Offer” below. |
· | We expressly reserve the right, at any time, to extend the period of time during which the exchange offer is open, and thereby delay acceptance of any old notes, by giving oral or written notice of an extension to the exchange agent and notice of that extension to the holders as described below. During any extension, all old notes previously tendered will remain subject to the exchange offer unless withdrawal rights are exercised. Any old notes not accepted for exchange for any reason will be returned without expense to the tendering holder promptly following the expiration or termination of the exchange offer. |
· | We expressly reserve the right to amend or terminate the exchange offer, and not to accept for exchange any old notes that we have not yet accepted for exchange, if any of the conditions of the exchange offer specified below under “Conditions to the Exchange Offer” are not satisfied. In the event of a material change in the exchange offer, including the waiver of a material condition, we will extend the offer period if necessary so that at least five business days remain in the exchange offer following notice of the material change. |
· | We will give oral or written notice of any extension, amendment, termination or non-acceptance described above to holders of the old notes promptly. If we extend the expiration date, we will give notice by means of a press release or other public announcement no later than 9:00 a.m., New York City time, on the business day after the previously scheduled expiration date. Without limiting the manner in which we may choose to make any public announcement and subject to applicable law, we will have no obligation to publish, advertise or otherwise communicate any public announcement other than by issuing a release to the Dow Jones News Service or other similar news service. |
· | Holders of old notes do not have any appraisal or dissenters’ rights in connection with the exchange offer. |
· | Old notes which are not tendered for exchange or are tendered but not accepted in connection with the exchange offer will remain outstanding and be entitled to the benefits of the indenture, but will not be entitled to any further registration rights under the registration rights agreement. |
· | We intend to conduct the exchange offer in accordance with the applicable requirements of the Exchange Act and the rules and regulations of the SEC thereunder. |
· | By executing, or otherwise becoming bound by, the letter of transmittal, you will be making the representations described below to us. See “—Resales of the New Notes.” |
Important rules concerning the exchange offer
You should note that:
· | All questions as to the validity, form, eligibility, time of receipt and acceptance of old notes tendered for exchange will be determined by DPL Inc. in its sole discretion, which determination shall be final and binding. |
· | We reserve the absolute right to reject any and all tenders of any particular old notes not properly tendered or to not accept any particular old notes which acceptance might, in our judgment or the judgment of our counsel, be unlawful. |
· | We also reserve the absolute right to waive any defects or irregularities or conditions of the exchange offer as to any particular old notes either before or after the expiration date, including the right to waive the ineligibility of any holder who seeks to tender old notes in the exchange offer. Unless we agree to waive any defect or irregularity in connection with the tender of old notes for exchange, you must cure any defect or irregularity within any reasonable period of time as we shall determine. |
· | Our interpretation of the terms and conditions of the exchange offer as to any particular old notes either before or after the expiration date shall be final and binding on all parties. |
· | Neither DPL Inc., the exchange agent nor any other person shall be under any duty to give notification of any defect or irregularity with respect to any tender of old notes for exchange, nor shall any of them incur any liability for failure to give any notification. |
Procedures for Tendering Old Notes
What to submit and how
If you, as the registered holder of an old security, wish to tender your old notes for exchange in the exchange offer, you must transmit a properly completed and duly executed letter of transmittal to Wells Fargo Bank, N.A. at the address set forth below under “Exchange Agent” on or prior to the expiration date.
In addition,
(1) certificates for old notes must be received by the exchange agent along with the letter of transmittal or
(2) a timely confirmation of a book-entry transfer of old notes, if such procedure is available, into the exchange agent’s account at DTC using the procedure for book-entry transfer described below, must be received by the exchange agent prior to the expiration date, or
(3) you must comply with the guaranteed delivery procedures described below.
The method of delivery of old notes, letters of transmittal and notices of guaranteed delivery is at your election and risk. If delivery is by mail, we recommend that registered mail, properly insured, with return receipt requested, be used. In all cases, sufficient time should be allowed to assure timely delivery. No letters of transmittal or old notes should be sent to DPL Inc.
How to sign your letter of transmittal and other documents
Signatures on a letter of transmittal or a notice of withdrawal, as the case may be, must be guaranteed unless the old notes being surrendered for exchange are tendered
(1) by a registered holder of the old notes who has not completed the box entitled “Special Issuance Instructions” or “Special Delivery Instructions” on the letter of transmittal or
(2) for the account of an eligible institution.
If signatures on a letter of transmittal or a notice of withdrawal, as the case may be, are required to be guaranteed, the guarantees must be by any of the following eligible institutions:
· | a firm which is a member of a registered national securities exchange or a member of the National Association of Securities Dealers, Inc. or |
· | a commercial bank or trust company having an office or correspondent in the United States. |
If the letter of transmittal is signed by a person or persons other than the registered holder or holders of old notes, the old notes must be endorsed or accompanied by appropriate powers of attorney, in either case signed exactly as the name or names of the registered holder or holders that appear on the old notes and with the signature guaranteed.
If the letter of transmittal or any old notes or powers of attorney are signed by trustees, executors, administrators, guardians, attorneys-in-fact, officers or corporations or others acting in a fiduciary or representative capacity, the person should so indicate when signing and, unless waived by DPL Inc., proper evidence satisfactory to DPL Inc. of its authority to so act must be submitted.
Acceptance of Old Notes for Exchange; Delivery of New Notes
Once all of the conditions to the exchange offer are satisfied or waived, we will accept, promptly after the expiration date, all old notes properly tendered and will issue the new notes promptly after the expiration of the exchange offer. See “Conditions to the Exchange Offer” below. For purposes of the exchange offer, our giving of oral or written notice of our acceptance to the exchange agent will be considered our acceptance of the exchange offer.
In all cases, we will issue new notes in exchange for old notes that are accepted for exchange only after timely receipt by the exchange agent of:
· | certificates for old notes, or |
· | a timely book-entry confirmation of transfer of old notes into the exchange agent’s account at DTC using the book-entry transfer procedures described below, and |
· | a properly completed and duly executed letter of transmittal. |
If we do not accept any tendered old notes for any reason included in the terms and conditions of the exchange offer or if you submit certificates representing old notes in a greater principal amount than you wish to exchange, we will return any unaccepted or non-exchanged old notes without expense to the tendering holder or, in the case of old notes tendered by book-entry transfer into the exchange agent’s account at DTC using the book-entry transfer procedures described below, non-exchanged old notes will be credited to an account maintained with DTC promptly following the expiration or termination of the exchange offer.
Book-Entry Transfer
The exchange agent will make a request to establish an account with respect to the old notes at DTC for purposes of the exchange offer promptly after the date of this prospectus. Any financial institution that is a participant in DTC’s systems may make book-entry delivery of old notes by causing DTC to transfer old notes into the exchange agent’s account in accordance with DTC’s Automated Tender Offer Program procedures for transfer. However, the exchange for the old notes so tendered will only be made after timely confirmation of book-entry transfer of old notes into the exchange agent’s account, and timely receipt by the exchange agent of an agent’s message, transmitted by DTC and received by the exchange agent and forming a part of a book-entry confirmation. The agent’s message must state that DTC has received an express acknowledgment from the participant tendering old notes that are the subject of that book-entry confirmation that the participant has received and agrees to be bound by the terms of the letter of transmittal, and that we may enforce the agreement against that participant.
Although delivery of old notes may be effected through book-entry transfer into the exchange agent’s account at DTC, the letter of transmittal, or a facsimile copy, properly completed and duly executed, with any required signature guarantees, must in any case be delivered to and received by the exchange agent at its address listed under “—Exchange Agent” on or prior to the expiration date.
If your old notes are held through DTC, you must complete a form called “instructions to registered holder and/or book-entry participant,” which will instruct the DTC participant through whom you hold your securities of your intention to tender your old notes or not tender your old notes. Please note that delivery of documents to DTC in accordance with its procedures does not constitute delivery to the exchange agent and we will not be able to
accept your tender of securities until the exchange agent receives a letter of transmittal and a book-entry confirmation from DTC with respect to your securities. A copy of that form is available from the exchange agent.
Guaranteed Delivery Procedures
If you are a registered holder of old notes and you want to tender your old notes but your old notes are not immediately available, or time will not permit your old notes to reach the exchange agent before the expiration date, or the procedure for book-entry transfer cannot be completed on a timely basis, a tender may be effected if
· | the tender is made through an eligible institution, |
· | prior to the expiration date, the exchange agent receives, by facsimile transmission, mail or hand delivery, from that eligible institution a properly completed and duly executed letter of transmittal and notice of guaranteed delivery, substantially in the form provided by us, stating: |
· | the name and address of the holder of old notes; |
· | the amount of old notes tendered; |
· | the tender is being made by delivering that notice; and |
· | guaranteeing that within three New York Stock Exchange trading days after the date of execution of the notice of guaranteed delivery, the certificates of all physically tendered old notes, in proper form for transfer, or a book-entry confirmation, as the case may be, will be deposited by that eligible institution with the exchange agent, and |
· | the certificates for all physically tendered old notes, in proper form for transfer, or a book-entry confirmation, as the case may be, are received by the exchange agent within three New York Stock Exchange trading days after the date of execution of the Notice of Guaranteed Delivery. |
Withdrawal Rights
You can withdraw your tender of old notes at any time on or prior to the expiration date.
For a withdrawal to be effective, a written notice of withdrawal must be received by the exchange agent at one of the addresses listed below under “Exchange Agent.” Any notice of withdrawal must specify:
· | the name of the person having tendered the old notes to be withdrawn |
· | the old notes to be withdrawn |
· | the principal amount of the old notes to be withdrawn |
· | if certificates for old notes have been delivered to the exchange agent, the name in which the old notes are registered, if different from that of the withdrawing holder |
· | if certificates for old notes have been delivered or otherwise identified to the exchange agent, then, prior to the release of those certificates, you must also submit the serial numbers of the particular certificates to be withdrawn and a signed notice of withdrawal with signatures guaranteed by an eligible institution unless you are an eligible institution. |
· | if old notes have been tendered using the procedure for book-entry transfer described above, any notice of withdrawal must specify the name and number of the account at DTC to be credited with the withdrawn old notes and otherwise comply with the procedures of that facility. |
Please note that all questions as to the validity, form, eligibility and time of receipt of notices of withdrawal will be determined by us, and our determination shall be final and binding on all parties. Any old notes so withdrawn will be considered not to have been validly tendered for exchange for purposes of the exchange offer.
If you have properly withdrawn old notes and wish to re-tender them, you may do so by following one of the procedures described under “Procedures for Tendering Old Notes” above at any time on or prior to the expiration date.
Conditions to the Exchange Offer
Notwithstanding any other provisions of the exchange offer, we will not be required to accept for exchange, or to issue new notes in exchange for, any old notes and may terminate or amend the exchange offer, if at any time before the expiration of the exchange offer, that acceptance or issuance would violate applicable law or any interpretation of the staff of the SEC.
That condition is for our sole benefit and may be asserted by us regardless of the circumstances giving rise to that condition. Our failure at any time to exercise the foregoing rights shall not be considered a waiver by us of that right. Our rights described in the prior paragraph are ongoing rights which we may assert at any time and from time to time prior to the expiration of the exchange offer.
Exchange Agent
Wells Fargo Bank, N.A. has been appointed as the exchange agent for the exchange offer. All executed letters of transmittal should be directed to the exchange agent at one of the addresses set forth below. Questions and requests for assistance, requests for additional copies of this prospectus or of the letter of transmittal and requests for notices of guaranteed delivery should be directed to the exchange agent, addressed as follows:
Deliver To:
By Registered or Certified Mail:
Wells Fargo Bank, N.A.
MAC - N9303-121
Corporate Trust Operations
P.O. Box 1517
Minneapolis, MN 55480-1517
By Overnight Delivery or Regular Mail:
Wells Fargo Bank, N.A
MAC - N9303-121
Corporate Trust Operations
Sixth Street &Marquette Avenue
Minneapolis, MN 55479
Facsimile Transmissions:
(612) 667-6282
Attn: Bondholder Communications
To Confirm by Email:
bondholdercommunications@wellsfargo.com
To Confirm by Telephone
or for Information:
(800) 344-5128
Attn: Bondholder Communications
Delivery to an address other than as listed above or transmission of instructions via facsimile other than as listed above does not constitute a valid delivery.
Fees and Expenses
The principal solicitation is being made by mail; however, additional solicitation may be made by telegraph, telephone or in person by our officers, regular employees and affiliates. We will not pay any additional compensation to any of our officers and employees who engage in soliciting tenders. We will not make any payment to brokers, dealers, or others soliciting acceptances of the exchange offer. However, we will pay the exchange agent reasonable and customary fees for its services and will reimburse it for its reasonable out-of-pocket expenses in connection with the exchange offer.
The estimated cash expenses to be incurred in connection with the exchange offer, including legal, accounting, SEC filing, printing and exchange agent expenses, will be paid by us and are estimated in the aggregate to be $425,000.
Accounting Treatment
We will record the new notes in our accounting records at the same carrying value as the old notes, which is the aggregate principal amount as reflected in our accounting records on the date of exchange. Accordingly, we will not recognize any gain or loss for accounting purposes upon the consummation of this exchange offer. We will capitalize the expenses of this exchange offer and amortize them over the life of the notes.
Transfer Taxes
Holders who tender their old notes for exchange will not be obligated to pay any transfer taxes in connection therewith, except that holders who instruct us to register new notes in the name of, or request that old notes not tendered or not accepted in the exchange offer be returned to, a person other than the registered tendering holder will be responsible for the payment of any applicable transfer tax thereon.
Resale of the New notes
Under existing interpretations of the staff of the SEC contained in several no-action letters to third parties, the new notes would in general be freely transferable after the exchange offer without further registration under the Securities Act. The relevant no-action letters include the Exxon Capital Holdings Corporation letter, which was made available by the SEC on May 13, 1988, and the Morgan Stanley & Co. Incorporated letter, made available on June 5, 1991.
However, any purchaser of old notes who is an “affiliate” of DPL Inc. or who intends to participate in the exchange offer for the purpose of distributing the new notes
(1) will not be able to rely on the interpretation of the staff of the SEC,
(2) will not be able to tender its old notes in the exchange offer and
(3) must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any sale or transfer of the securities unless that sale or transfer is made using an exemption from those requirements.
By executing, or otherwise becoming bound by, the Letter of Transmittal each holder of the old notes will represent that:
(1) it is not our “affiliate”;
(2) any new notes to be received by it were acquired in the ordinary course of its business; and
(3) it has no arrangement or understanding with any person to participate, and is not engaged in and does not intend to engage, in the “distribution,” within the meaning of the Securities Act, of the new notes.
In addition, in connection with any resales of new notes, any broker-dealer participating in the exchange offer who acquired securities for its own account as a result of market-making or other trading activities must deliver a prospectus meeting the requirements of the Securities Act. The SEC has taken the position in the Shearman & Sterling no-action letter, which it made available on July 2, 1993, that participating broker-dealers may fulfill their
prospectus delivery requirements with respect to the new notes, other than a resale of an unsold allotment from the original sale of the old notes, with the prospectus contained in the exchange offer registration statement. Under the registration rights agreement, we are required to allow participating broker-dealers and other persons, if any, subject to similar prospectus delivery requirements to use this prospectus as it may be amended or supplemented from time to time, in connection with the resale of new notes.
Failure to Exchange
Holders of old notes who do not exchange their old notes for new notes under the exchange offer will remain subject to the restrictions on transfer of such old notes as set forth in the legend printed on the notes as a consequence of the issuance of the old notes pursuant to the exemptions from, or in transactions not subject to, the registration requirements of the Securities Act and applicable state securities laws, and otherwise set forth in the confidential offering memorandum distributed in connection with the private offering of the old notes.
Other
Participating in the exchange offer is voluntary, and you should carefully consider whether to accept. You are strongly urged to consult your financial, legal and tax advisors in making your own decision on what action to take.
The exchange of old notes for new notes in the exchange offer will not be a taxable event for holders. When a holder exchanges an old note for a new note in the exchange offer, the holder will have the same adjusted tax basis and holding period in the new note as in the old note immediately before the exchange.
Persons considering the exchange of old notes for new notes should consult their own tax advisers concerning the U.S. federal income tax consequences in light of their particular situations as well as any tax consequences arising under the laws of any other taxing jurisdiction.
Each broker-dealer that receives new notes for its own account in the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of new notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of new notes received in exchange for old notes where old notes were acquired as a result of market-making activities or other trading activities. We have agreed that, for a period of 90 days after the expiration date, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any resale of new notes received by it in exchange for old notes.
We will not receive any proceeds from any sale of new notes by broker-dealers.
New notes received by broker-dealers for their own account in the exchange offer may be sold from time to time in one or more transactions:
· | in the over-the-counter market; |
· | in negotiated transactions; |
· | through the writing of options on the new notes; or |
· | a combination of those methods of resale, |
at market prices prevailing at the time of resale, at prices related to prevailing market prices or negotiated prices.
Any resale may be made:
· | directly to purchasers; or |
· | to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any broker-dealer or the purchasers of any new notes. |
Any broker-dealer that resells new notes that were received by it for its own account in the exchange offer and any broker or dealer that participates in a distribution of those new notes may be considered to be an “underwriter” within the meaning of the Securities Act. Any profit on any resale of those new notes and any commission or concessions received by any of those persons may be considered to be underwriting compensation under the Securities Act. The letter of transmittal states that, by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be considered to admit that it is an “underwriter” within the meaning of the Securities Act.
For a period of 90 days after the expiration date, we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests those documents in the letter of transmittal. We have agreed to pay all expenses incident to the exchange offer, other than commissions or concessions of any brokers or dealers and will indemnify the holders of the securities, including any broker-dealers, against some liabilities, including liabilities under the Securities Act.
Davis Polk & Wardwell LLP will opine for us on whether the new notes are valid and binding obligations of DPL Inc. and will rely on the opinion of Timothy G. Rice, Esq., Vice President, Acting General Counsel and Corporate Secretary of DPL Inc. with respect to certain matters under the laws of the State of Ohio.
The consolidated financial statements and Schedule I – “Valuation and Qualifying Accounts” of DPL Inc. and subsidiaries as of December 31, 2010, and for each of the years in the two year period ended December 31, 2010, and for the period from January 1, 2011 through November 27, 2011, have been included herein and the registration statement in reliance upon the report of KPMG LLP, independendent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.
The consolidated financial statements and Schedule I as listed in the index to the Financial Statements of DPL Inc. and subsidiaries as of December 31, 2011 and for the period from November 28, 2011 to December 31, 2011, appearing in this prospectus and the registration statement of which it forms a part have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report therein appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.
We have filed with the SEC, Washington, D.C. 20549, a registration statement on Form S-4 under the Securities Act with respect to our offering of the new notes. This prospectus does not contain all of the information set forth in the registration statement and the exhibits and schedules thereto. For further information with respect to the company and the new notes, reference is made to the registration statement and the exhibits and any schedules filed therewith. Statements contained in this prospectus as to the contents of any contract or other document referred to are not necessarily complete and in each instance, if such contract or document is filed as an exhibit, reference is made to the copy of such contract or other document filed as an exhibit to the registration statement, each statement being qualified in all respects by such reference. A copy of the registration statement, including the exhibits and schedules thereto, may be read and copied at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains an Internet website that contains reports, proxy statements and other information about issuers, like us, that file electronically with the SEC. The address of that site is at http://www.sec.gov.
If for any reason we are not required to comply with the reporting requirements of the Securities Exchange Act of 1934, as amended, or we do not otherwise report on an annual or quarterly basis on forms provided for such annual and quarterly reporting pursuant to rules and regulations promulgated by the SEC, we are still required under the indenture to deliver (which may be accomplished through posting on the internet) to the trustee and to holders of the notes, without any cost to any holder: (1) within 90 days after the end of each fiscal year, audited financial statements and (2) within 45 days after the end of each of the first three fiscal quarters of each fiscal year, quarterly unaudited financial statements. We are also required under the indenture to provide without charge upon the written request of (1) a holder of any notes or (2) a prospective holder of any of the notes who is a “qualified institutional buyer” within the meaning of Rule 144A and is designated by an existing holder of any of the notes with the information with respect to the Company required to be delivered under Rule 144A(d)(f) under the Securities Act to enable resales of the notes to be made pursuant to Rule 144A.
Any such requests should be directed to us at: DPL Inc., 1065 Woodman Drive, Dayton, Ohio 45432, Phone: (937) 224-6000, Attention: Treasurer.
We also maintain an Internet site at http://www.dplinc.com. Our website and the information contained therein or connected thereto shall not be deemed to be a part of this prospectus or the registration statement of which it forms a part.
DPL Inc. Annual Consolidated Financial Statements | Page No. | |
F-2 | ||
F-4 | ||
F-5 | ||
F-6 | ||
F-7 | ||
F-9 | ||
F-10 | ||
F-78 |
DPL Inc. Interim Unaudited Condensed Consolidated Financial Statements | ||
F-80 | ||
F-81 | ||
F-82 | ||
F-83 | ||
F-85 |
To the Board of Directors of DPL Inc.:
We have audited the accompanying Consolidated Balance Sheet of DPL Inc. as of December 31, 2011, and the related Consolidated Statements of Operations, Comprehensive Income / (Loss), Cash Flows, and Shareholders’ Equity for the period from November 28, 2011 through December 31, 2011. Our audit also included the financial statement schedule listed in the index at Schedule I. These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of DPL Inc. at December 31, 2011 and the consolidated results of its operations and its cash flows for the period from November 28, 2011 through December 31, 2011, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/s/ Ernst & Young LLP
Cincinnati, Ohio
March 27, 2012, except for Notes 1, 2, 5, 6, 8, and 19, as to which the date is August 24, 2012
Report of Independent Registered Public Accounting Firm
The Board of Directors
DPL Inc.:
We have audited the accompanying consolidated balance sheet of DPL Inc. and its subsidiaries (DPL) as of December 31, 2010, and the related consolidated statements of results of operations, comprehensive income / (loss), shareholders’ equity and cash flows for each of the years ended December 31, 2010 and 2009, and the consolidated statements of results of operations, comprehensive income / (loss), shareholders’ equity and cash flows for the period from January 1, 2011 through November 27, 2011. In connection with our audits of the financial statements, we also have audited the financial statement schedule, “Schedule I – Valuation and Qualifying Accounts” for each of the years ended December 31, 2010 and 2009 and for the period from January 1, 2011 through November 27, 2011. These financial statements are the responsibility of DPL’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinions.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of DPL as of December 31, 2010, and the results of its operations and its cash flows for each of the years ended December 31, 2010 and 2009 and for the period from January 1, 2011 through November 27, 2011, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
/s/ KPMG LLP
Philadelphia, Pennsylvania
March 27, 2012
Successor | Predecessor | ||||||||||||||||
November 28, 2011 | January 1, 2011 | ||||||||||||||||
through | through | Years ended December 31, | |||||||||||||||
$ in millions except per share amounts | December 31, 2011 | November 27, 2011 | 2010 | 2009 | |||||||||||||
Revenues | $ | 156.9 | $ | 1,670.9 | $ | 1,831.4 | $ | 1,539.4 | |||||||||
Cost of revenues: | |||||||||||||||||
Fuel | 35.8 | 355.8 | 383.9 | 330.4 | |||||||||||||
Purchased power | 36.7 | 404.6 | 387.4 | 260.2 | |||||||||||||
Amortization of intangibles | 11.6 | - | - | - | |||||||||||||
Total cost of revenues | 84.1 | 760.4 | 771.3 | 590.6 | |||||||||||||
Gross margin | 72.8 | 910.5 | 1,060.1 | 948.8 | |||||||||||||
Operating expenses: | |||||||||||||||||
Operation and maintenance | 47.5 | 377.8 | 340.6 | 306.5 | |||||||||||||
Depreciation and amortization | 11.6 | 129.4 | 139.4 | 145.5 | |||||||||||||
General taxes | 7.6 | 75.5 | 75.7 | 68.6 | |||||||||||||
Total operating expenses | 66.7 | 582.7 | 555.7 | 520.6 | |||||||||||||
Operating income | 6.1 | 327.8 | 504.4 | 428.2 | |||||||||||||
Other income / (expense), net | |||||||||||||||||
Investment income (loss) | 0.1 | 0.4 | 1.8 | (0.6 | ) | ||||||||||||
Interest expense | (11.5 | ) | (58.7 | ) | (70.6 | ) | (83.0 | ) | |||||||||
Charge for early redemption of debt | - | (15.3 | ) | - | - | ||||||||||||
Other income / (deductions) | (0.3 | ) | (1.7 | ) | (2.3 | ) | (3.0 | ) | |||||||||
Total other income / (expense), net | (11.7 | ) | (75.3 | ) | (71.1 | ) | (86.6 | ) | |||||||||
Earnings (loss) from operations before income tax | (5.6 | ) | 252.5 | 433.3 | 341.6 | ||||||||||||
Income tax expense | 0.6 | 102.0 | 143.0 | 112.5 | |||||||||||||
Net income (loss) | $ | (6.2 | ) | $ | 150.5 | $ | 290.3 | $ | 229.1 | ||||||||
Average number of common shares outstanding (millions): | |||||||||||||||||
Basic | N/A | 114.5 | 115.6 | 112.9 | |||||||||||||
Diluted | N/A | 115.1 | 116.1 | 114.2 | |||||||||||||
Earnings per share of common stock: | |||||||||||||||||
Basic | N/A | $ | 1.31 | $ | 2.51 | $ | 2.03 | ||||||||||
Diluted | N/A | $ | 1.31 | $ | 2.50 | $ | 2.01 | ||||||||||
Dividends declared per share of common stock | N/A | $ | 1.54 | $ | 1.21 | $ | 1.14 | ||||||||||
See Notes to Consolidated Financial Statements. |
DPL INC. | |||||||||
Successor | Predecessor | ||||||||||||||||
November 28, 2011 through December 31, 2011 | January 1, 2011 through November 27, 2011 | Years ended December 31, | |||||||||||||||
$ in millions | 2010 | 2009 | |||||||||||||||
Net income (loss) | $ | (6.2 | ) | $ | 150.5 | $ | 290.3 | $ | 229.1 | ||||||||
Available-for-sale securities activity: | |||||||||||||||||
Change in fair value of available-for-sale securities, net of income | |||||||||||||||||
tax benefit/ (expense) of $0.0 and $0.0, $(0.2) and $(0.3), respectively | - | - | 0.4 | 0.5 | |||||||||||||
Total change in fair value of available-for-sale securities | - | - | 0.4 | 0.5 | |||||||||||||
Derivative activity: | |||||||||||||||||
Change in derivative fair value, net of income tax benefit / | |||||||||||||||||
(expense) of $0.3, $31.2, $(6.6) and $(1.2), respectively | (0.5 | ) | (58.2 | ) | 12.3 | 2.2 | |||||||||||
Reclassification of earnings, net of income tax (expense) / benefit | |||||||||||||||||
of $0.0, $(0.3), $2.0 and $1.8, respectively | - | (0.3 | ) | (5.9 | ) | (5.9 | ) | ||||||||||
Total change in fair value of derivatives | (0.5 | ) | (58.5 | ) | 6.4 | (3.7 | ) | ||||||||||
Pension and postretirement activity: | |||||||||||||||||
Prior service cost for the period, net of income tax benefit / | |||||||||||||||||
(expense) of $0.2, $0.0, $(3.7) and $5.6, respectively | (0.2 | ) | 0.1 | 7.0 | (10.5 | ) | |||||||||||
Net loss for the period, net of income tax benefit / (expense) | |||||||||||||||||
of $(0.2), $0.7, $4.0 and $(3.1), respectively | 0.3 | 0.3 | (6.1 | ) | 5.7 | ||||||||||||
Reclassification to earnings, net of income tax benefit / (expense) | |||||||||||||||||
of $0.0,$(1.5), $(1.3) and $(1.1), respectively | - | 2.8 | 2.4 | 2.1 | |||||||||||||
Total change in unfunded pension obligation | 0.1 | 3.2 | 3.3 | (2.7 | ) | ||||||||||||
Other comprehensive income / (loss) | (0.4 | ) | (55.3 | ) | 10.1 | (5.9 | ) | ||||||||||
Net comprehensive income / (loss) | $ | (6.6 | ) | $ | 95.2 | $ | 300.4 | $ | 223.2 | ||||||||
See Notes to Consolidated Financial Statements. |
DPL INC. | |||||||||
Successor | Predecessor | ||||||||||||||||
November 28, 2011 | January 1, 2011 | ||||||||||||||||
through | through | Years ended December 31, | |||||||||||||||
$ in millions except per share amounts | December 31, 2011 | November 27, 2011 | 2010 | 2009 | |||||||||||||
Cash flows from operating activities: | |||||||||||||||||
Net income / (loss) | $ | (6.2 | ) | $ | 150.5 | $ | 290.3 | $ | 229.1 | ||||||||
Adjustments to reconcile Net income to Net cash | |||||||||||||||||
provided by operating activities: | |||||||||||||||||
Depreciation and amortization | 11.6 | 129.4 | 139.4 | 145.5 | |||||||||||||
Amortization of other assets | 11.6 | - | - | - | |||||||||||||
Deferred income taxes | 0.1 | 65.5 | 59.9 | 201.6 | |||||||||||||
Charge for early redemption of debt | - | 15.3 | - | - | |||||||||||||
Changes in certain assets and liabilities: | |||||||||||||||||
Accounts receivable | (12.3 | ) | 14.6 | (1.5 | ) | 39.3 | |||||||||||
Inventories | (2.5 | ) | (11.5 | ) | 10.4 | (20.6 | ) | ||||||||||
Prepaid taxes | 0.6 | 7.1 | (9.0 | ) | - | ||||||||||||
Taxes applicable to subsequent years | (71.2 | ) | 58.4 | (4.1 | ) | (1.5 | ) | ||||||||||
Deferred regulatory costs, net | 0.1 | (14.4 | ) | 21.8 | (23.6 | ) | |||||||||||
Accounts payable | 6.6 | (0.6 | ) | 17.8 | (65.0 | ) | |||||||||||
Accrued taxes payable | 78.5 | (58.6 | ) | 1.2 | (2.4 | ) | |||||||||||
Accrued interest payable | 6.4 | (8.1 | ) | (5.1 | ) | (1.5 | ) | ||||||||||
Pension, retiree and other benefits | 10.2 | (34.2 | ) | (58.2 | ) | 15.2 | |||||||||||
Unamortized investment tax credit | (0.2 | ) | (2.3 | ) | (2.8 | ) | (2.8 | ) | |||||||||
Insurance and claims costs | (0.1 | ) | 4.3 | (6.1 | ) | (1.4 | ) | ||||||||||
Other deferred debits, DPL stock held in trust | (26.9 | ) | - | - | - | ||||||||||||
Other | (7.2 | ) | 10.1 | 10.2 | 12.8 | ||||||||||||
Net cash provided by (used for) operating activities | (0.9 | ) | 325.5 | 464.2 | 524.7 | ||||||||||||
Cash flows from investing activities: | |||||||||||||||||
Capital expenditures | (30.5 | ) | (174.2 | ) | (152.7 | ) | (172.3 | ) | |||||||||
Proceeds from sale of property - other | - | - | - | 1.2 | |||||||||||||
Purchase of MC Squared | - | (8.3 | ) | - | - | ||||||||||||
Purchases of short-term investments and securities | - | (1.7 | ) | (86.4 | ) | (20.7 | ) | ||||||||||
Sales of short-term investments and securities | - | 70.9 | 17.1 | 25.7 | |||||||||||||
Other investing activities, net | (0.4 | ) | 1.5 | 1.4 | 1.4 | ||||||||||||
Net cash used for investing activities | (30.9 | ) | (111.8 | ) | (220.6 | ) | (164.7 | ) | |||||||||
Cash flows from financing activities: | |||||||||||||||||
Dividends paid on common stock | (63.0 | ) | (113.0 | ) | (139.7 | ) | (128.8 | ) | |||||||||
Repurchase of DPL common stock | - | - | (56.4 | ) | (64.4 | ) | |||||||||||
Repurchase of warrants | - | - | - | (25.2 | ) | ||||||||||||
Proceeds from exercise of warrants | - | 14.7 | - | 77.7 | |||||||||||||
Proceeds from liquidation of DPL stock, held in trust | 26.9 | - | - | - | |||||||||||||
Retirement of long-term debt | - | (297.5 | ) | - | (175.0 | ) | |||||||||||
Early redemption of Capital Trust II notes | - | (122.0 | ) | - | (52.4 | ) | |||||||||||
Premium paid for early redemption of debt | - | (12.2 | ) | - | (3.7 | ) | |||||||||||
Issuance of long-term debt | 125.0 | 300.0 | - | - | |||||||||||||
Payment of MC Squared debt | - | (13.5 | ) | - | - | ||||||||||||
Withdrawal of restricted funds held in trust, net | - | - | - | 14.5 | |||||||||||||
Withdrawals from revolving credit facilities | - | 50.0 | - | 260.0 | |||||||||||||
Repayment of borrowings from revolving credit facilities | - | (50.0 | ) | - | (260.0 | ) | |||||||||||
Exercise of stock options | - | 1.6 | 1.4 | 9.0 | |||||||||||||
Tax impact related to exercise of stock options | - | 1.4 | 0.2 | 0.7 | |||||||||||||
Net cash provided by (used for) financing activities | 88.9 | (240.5 | ) | (194.5 | ) | (347.6 | ) | ||||||||||
Cash and cash equivalents: | |||||||||||||||||
Net change | 57.1 | (26.8 | ) | 49.1 | 12.4 | ||||||||||||
Assumption of cash at acquisition | 19.2 | - | - | - | |||||||||||||
Balance at beginning of period | 97.2 | 124.0 | 74.9 | 62.5 | |||||||||||||
Cash and cash equivalents at end of period | $ | 173.5 | $ | 97.2 | $ | 124.0 | $ | 74.9 | |||||||||
Supplemental cash flow information: | |||||||||||||||||
Interest paid, net of amounts capitalized | 6.0 | 62.0 | 77.1 | 84.3 | |||||||||||||
Income taxes (refunded) / paid, net | - | 25.6 | 87.1 | (94.6 | ) | ||||||||||||
Non-cash financing and investing activities: | |||||||||||||||||
Accruals for capital expenditures | 7.6 | 18.9 | 23.2 | 20.8 | |||||||||||||
Long-term liability incurred for the purchase of plant assets | - | 18.7 | - | - | |||||||||||||
Assumption of debt with acquisition | 1,250.0 | - | - | - | |||||||||||||
See Notes to Consolidated Financial Statements. |
DPL INC. | |||||||
CONSOLIDATED BALANCE SHEETS |
Successor | Predecessor | ||||||||
December 31, | December 31, | ||||||||
$ in millions | 2011 | 2010 | |||||||
ASSETS | |||||||||
Current assets: | |||||||||
Cash and cash equivalents | $ | 173.5 | $ | 124.0 | |||||
Short-term investments | - | 69.3 | |||||||
Accounts receivable, net (Note 3) | 219.1 | 215.5 | |||||||
Inventories (Note 3) | 125.8 | 112.6 | |||||||
Taxes applicable to subsequent years | 76.5 | 63.7 | |||||||
Regulatory assets, current (Note 4) | 20.8 | 22.0 | |||||||
Other prepayments and current assets | 36.2 | 40.6 | |||||||
Total current assets | 651.9 | 647.7 | |||||||
Property, plant and equipment: | |||||||||
Property, plant and equipment | 2,360.3 | 5,353.6 | |||||||
Less: Accumulated depreciation and amortization | (7.5 | ) | (2,555.2 | ) | |||||
2,352.8 | 2,798.4 | ||||||||
Construction work in process | 152.3 | 119.7 | |||||||
Total net property, plant and equipment | 2,505.1 | 2,918.1 | |||||||
Other non-current assets: | |||||||||
Regulatory assets, non-current (Note 4) | 177.8 | 167.0 | |||||||
Goodwill | 2,568.1 | - | |||||||
Intangible assets, net of amortization (Note 6) | 142.4 | 2.7 | |||||||
Other deferred assets | 51.8 | 77.8 | |||||||
Total other non-current assets | 2,940.1 | 247.5 | |||||||
Total Assets | $ | 6,097.1 | $ | 3,813.3 | |||||
See Notes to Consolidated Financial Statements. |
DPL INC. | ||||||||||||||||||
CONSOLIDATED BALANCE SHEETS | ||||||||||||||||||
Successor | Predecessor | |||||||||||||||||
December 31, | December 31, | |||||||||||||||||
$ in millions | 2011 | 2010 | ||||||||||||||||
LIABILITIES AND SHAREHOLDERS' EQUITY | ||||||||||||||||||
Current liabilities: | ||||||||||||||||||
Current portion - long-term debt (Note 7) | $ | 0.4 | $ | 297.5 | ||||||||||||||
Accounts payable | 111.1 | 98.7 | ||||||||||||||||
Accrued taxes | 76.3 | 68.1 | ||||||||||||||||
Accrued interest | 30.2 | 18.4 | ||||||||||||||||
Customer security deposits | 15.9 | 18.7 | ||||||||||||||||
Regulatory liabilities, current (Note 4) | 0.5 | 10.0 | ||||||||||||||||
Other current liabilities | 61.1 | 43.2 | ||||||||||||||||
Total current liabilities | 295.5 | 554.6 | ||||||||||||||||
Non-current liabilities: | ||||||||||||||||||
Long-term debt (Note 7) | 2,628.9 | 1,026.6 | ||||||||||||||||
Deferred taxes (Note 8) | 505.7 | 623.1 | ||||||||||||||||
Regulatory liabilities, non-current (Note 4) | 118.6 | 114.0 | ||||||||||||||||
Pension, retiree and other benefits | 47.5 | 64.9 | ||||||||||||||||
Unamortized investment tax credit | 3.6 | 32.4 | ||||||||||||||||
Insurance and claims costs | 14.2 | 10.1 | ||||||||||||||||
Other deferred credits | 234.0 | 146.2 | ||||||||||||||||
Total non-current liabilities | 3,552.5 | 2,017.3 | ||||||||||||||||
Redeemable preferred stock of subsidiary | 18.4 | 22.9 | ||||||||||||||||
Commitments and contingencies (Note 18) | ||||||||||||||||||
Common shareholders' equity: | ||||||||||||||||||
Common stock: | Successor | Predecessor | ||||||||||||||||
No par value | Par value $0.01 | |||||||||||||||||
December 2011 | December 2010 | |||||||||||||||||
Shares authorized | 1,500 | 250,000,000 | ||||||||||||||||
Shares issued | 1 | 163,724,211 | ||||||||||||||||
Shares outstanding | 1 | 116,924,844 | - | 1.2 | ||||||||||||||
Other paid-in capital | 2,237.3 | - | ||||||||||||||||
Warrants | - | 2.7 | ||||||||||||||||
Common stock held by employee plans | - | (12.5 | ) | |||||||||||||||
Accumulated other comprehensive loss | (0.4 | ) | (18.9 | ) | ||||||||||||||
Retained earnings / (deficit) | (6.2 | ) | 1,246.0 | |||||||||||||||
Total common shareholders' equity | 2,230.7 | 1,218.5 | ||||||||||||||||
Total Liabilities and Shareholders' Equity | $ | 6,097.1 | $ | 3,813.3 | ||||||||||||||
See Notes to Consolidated Financial Statements. |
DPL INC. |
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY |
Common | ||||||||||||||||||||||||||||||||
Stock | Accumulated | |||||||||||||||||||||||||||||||
Common Stock (b) | Held by | Other | Other | |||||||||||||||||||||||||||||
in millions (except Outstanding | Outstanding | Employee | Comprehensive | Paid-in | Retained | |||||||||||||||||||||||||||
Shares) | Shares | Amount | Warrants | Plans | Income /(Loss) | Capital | Earnings | Total | ||||||||||||||||||||||||
Beginning balance | 115,961,880 | $ | 1.2 | $ | 31.0 | $ | (27.6 | ) | $ | (23.1 | ) | $ | - | $ | 1,015.6 | $ | 997.1 | |||||||||||||||
2009 (Predecessor): | ||||||||||||||||||||||||||||||||
Net income | 229.1 | |||||||||||||||||||||||||||||||
Change in unrealized gains (losses) on financial instruments, net of tax | 0.5 | |||||||||||||||||||||||||||||||
Change in deferred gains (losses) on cash flow hedges, net of tax | (3.7 | ) | ||||||||||||||||||||||||||||||
Change in unrealized gains (losses) on pension and postretirement benefits, net of tax | (2.7 | ) | ||||||||||||||||||||||||||||||
Total comprehensive income | 223.2 | |||||||||||||||||||||||||||||||
Common stock dividends (a) | (128.8 | ) | (128.8 | ) | ||||||||||||||||||||||||||||
Repurchase of warrants | (13.6 | ) | (11.6 | ) | (25.2 | ) | ||||||||||||||||||||||||||
Exercise of warrants | 4,973,629 | (14.5 | ) | 92.2 | 77.7 | |||||||||||||||||||||||||||
Treasury stock purchased | (2,388,391 | ) | (64.4 | ) | (64.4 | ) | ||||||||||||||||||||||||||
Treasury stock reissued | 419,649 | 10.1 | 10.1 | |||||||||||||||||||||||||||||
Tax effects to equity | 0.8 | 0.8 | ||||||||||||||||||||||||||||||
Employee / Director stock plans | 8.3 | 0.5 | 8.8 | |||||||||||||||||||||||||||||
Other | 0.6 | 0.6 | ||||||||||||||||||||||||||||||
Ending balance | 118,966,767 | $ | 1.2 | $ | 2.9 | $ | (19.3 | ) | $ | (29.0 | ) | $ | - | $ | 1,144.1 | $ | 1,099.9 |
2010 (Predecessor): | ||||||||||||||||||||||||||||||||
Net income | 290.3 | |||||||||||||||||||||||||||||||
Change in unrealized gains (losses) on financial instruments, net of tax | 0.4 | |||||||||||||||||||||||||||||||
Change in deferred gains (losses) on cash flow hedges, net of tax | 6.4 | |||||||||||||||||||||||||||||||
Change in unrealized gains (losses) on pension and postretirement benefits, net of tax | 3.3 | |||||||||||||||||||||||||||||||
Total comprehensive income | 300.4 | |||||||||||||||||||||||||||||||
Common stock dividends (a) | (139.7 | ) | (139.7 | ) | ||||||||||||||||||||||||||||
Repurchase of warrants | (0.2 | ) | (0.2 | ) | ||||||||||||||||||||||||||||
Exercise of warrants | 18,288 | - | ||||||||||||||||||||||||||||||
Treasury stock purchased | (2,182,751 | ) | (56.4 | ) | (56.4 | ) | ||||||||||||||||||||||||||
Treasury stock reissued | 122,540 | 2.4 | 2.4 | |||||||||||||||||||||||||||||
Tax effects to equity | 0.2 | 0.2 | ||||||||||||||||||||||||||||||
Employee / Director stock plans | 6.8 | 5.1 | 11.9 | |||||||||||||||||||||||||||||
Ending balance | 116,924,844 | $ | 1.2 | $ | 2.7 | $ | (12.5 | ) | $ | (18.9 | ) | $ | - | $ | 1,246.0 | $ | 1,218.5 | |||||||||||||||
January 1, 2011 through November 27, 2011 (Predecessor): | ||||||||||||||||||||||||||||||||
Net income | 150.5 | |||||||||||||||||||||||||||||||
Change in unrealized gains (losses) on financial instruments, net of tax | ||||||||||||||||||||||||||||||||
Change in deferred gains (losses) on cash flow hedges, net of tax | (58.5 | ) | ||||||||||||||||||||||||||||||
Change in unrealized gains (losses) on pension and postretirement benefits, net of tax | 3.2 | |||||||||||||||||||||||||||||||
Total comprehensive income | 95.2 | |||||||||||||||||||||||||||||||
Common stock dividends (a) | (176.0 | ) | (176.0 | ) | ||||||||||||||||||||||||||||
Repurchase of warrants | (1.1 | ) | (1.1 | ) | ||||||||||||||||||||||||||||
Exercise of warrants | ||||||||||||||||||||||||||||||||
Treasury stock reissued | 805,150 | 18.2 | 18.2 | |||||||||||||||||||||||||||||
Tax effects to equity | 1.4 | 1.4 | ||||||||||||||||||||||||||||||
Employee / Director stock plans | 12.7 | 1.8 | 14.5 | |||||||||||||||||||||||||||||
Other | (0.1 | ) | (0.1 | ) | (0.2 | ) | ||||||||||||||||||||||||||
Ending balance | 117,729,994 | $ | 1.2 | $ | 1.6 | $ | 0.2 | $ | (74.3 | ) | $ | - | $ | 1,241.8 | $ | 1,170.5 | ||||||||||||||||
November 28, 2011 through December 31, 2011 (Successor): | ||||||||||||||||||||||||||||||||
Capitalization at merger | 1 | $ | 2,235.6 | $ | - | $ | 2,235.6 | |||||||||||||||||||||||||
Net income | (6.2 | ) | ||||||||||||||||||||||||||||||
Change in unrealized gains (losses) on financial instruments, net of tax | ||||||||||||||||||||||||||||||||
Change in deferred gains (losses) on cash flow hedges, net of tax | (0.5 | ) | ||||||||||||||||||||||||||||||
Change in unrealized gains (losses) on pension and postretirement benefits, net of tax | 0.1 | |||||||||||||||||||||||||||||||
Total comprehensive loss | (6.6 | ) | ||||||||||||||||||||||||||||||
Contribution from Parent | 1.7 | 1.7 | ||||||||||||||||||||||||||||||
Ending balance | 1 | $ | - | $ | - | $ | - | $ | (0.4 | ) | $ | 2,237.3 | $ | (6.2 | ) | $ | 2,230.7 | |||||||||||||||
(a) Common stock dividends per share were $1.14 in 2009, $1.21 per share in 2010 and $1.54 per share in 2011. | ||||||||||||||||||||||||||||||||
(b) $0.01 par value, 250,000,000 shares authorized. | ||||||||||||||||||||||||||||||||
See Notes to Consolidated Financial Statements. |
D P L I n c.
1. Overview and Summary of Significant Accounting Policies |
Description of Business
DPL is a diversified regional energy company organized in 1985 under the laws of Ohio. DPL’s two reportable segments are the Utility segment, comprised of its DP&L subsidiary, and the Competitive Retail segment, comprised of its DPLER subsidiary. Refer to Note 18 for more information relating to these reportable segments.
On November 28, 2011, DPL was acquired by AES in the Merger and DPL became a wholly-owned subsidiary of AES. See Note 2.
DP&L is a public utility incorporated in 1911 under the laws of Ohio. DP&L is engaged in the generation, transmission, distribution and sale of electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio. Electricity for DP&L's 24 county service area is primarily generated at eight coal-fired power plants and is distributed to more than 500,000 retail customers. Principal industries served include automotive, food processing, paper, plastic manufacturing and defense.
DP&L's sales reflect the general economic conditions and seasonal weather patterns of the area. DP&L sells any excess energy and capacity into the wholesale market.
DPLER sells competitive retail electric service, under contract, to residential, commercial and industrial customers. DPLER’s operations include those of its wholly-owned subsidiary, MC Squared, which was acquired on February 28, 2011. DPLER has approximately 40,000 customers currently located throughout Ohio and Illinois. DPLER does not own any transmission or generation assets, and all of DPLER’s electric energy was purchased from DP&L or PJM to meet its sales obligations. DPLER’s sales reflect the general economic conditions and seasonal weather patterns of the area.
DPL’s other significant subsidiaries include DPLE, which owns and operates peaking generating facilities from which it makes wholesale sales of electricity and MVIC, our captive insurance company that provides insurance services to us and our subsidiaries. All of DPL’s subsidiaries are wholly-owned.
DPL also has a wholly-owned business trust, DPL Capital Trust II, formed for the purpose of issuing trust capital securities to investors.
DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators while its generation business is deemed competitive under Ohio law. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are expected to be recovered in future customer rates, and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs.
DPL and its subsidiaries employed 1,510 people as of December 31, 2011, of which 1,468 employees were employed by DP&L. Approximately 53% of all employees are under a collective bargaining agreement which expires on October 31, 2014.
Financial Statement Presentation
We prepare Consolidated Financial Statements for DPL. DPL’s Consolidated Financial Statements include the accounts of DPL and its wholly-owned subsidiaries except for DPL Capital Trust II which is not consolidated, consistent with the provisions of GAAP. DP&L’s undivided ownership interests in certain coal-fired generating plants are included in the financial statements at amortized cost, which was adjusted to fair value at the Merger date. Operating revenues and expenses are included on a pro-rata basis in the corresponding lines in the Consolidated Statement of Operations. See Note 5 for more information.
Certain excise taxes collected from customers have been reclassified out of revenue and operating expenses in the 2010 and 2009 presentation to conform to AES’ presentation of these items. Certain immaterial amounts from prior periods have been reclassified to conform to the current reporting presentation.
Deferred SECA revenue of $15.4 million at December 31, 2010 was reclassified from Regulatory liabilities to Other deferred credits. The balance of deferred SECA revenue at December 31, 2011 and 2010 was $17.8 million and $15.4 million, respectively. The amount at December 31, 2011 includes interest of $5.2 million. The FERC-approved SECA billings are unearned revenue where the earnings process is not complete and do not represent a potential overpayment by retail ratepayers or potential refunds of costs that had been previously charged to retail ratepayers through rates. Therefore, any amounts that are ultimately collected related to these charges would not be a reduction to future rates charged to retail ratepayers and therefore do not meet the criteria for recording as a regulatory liability under GAAP.
All material intercompany accounts and transactions are eliminated in consolidation.
The preparation of financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the revenues and expenses of the periods reported. Actual results could differ from these estimates. Significant items subject to such estimates and judgments include: the carrying value of Property, plant and equipment; unbilled revenues; the valuation of derivative instruments; the valuation of insurance and claims liabilities; the valuation of allowances for receivables and deferred income taxes; regulatory assets and liabilities; reserves recorded for income tax exposures; litigation; contingencies; the valuation of AROs; assets and liabilities related to employee benefits; goodwill; and intangibles.
On November 28, 2011, AES completed the Merger with DPL. As a result of the Merger, DPL is a wholly-owned, subsidiary of AES. DPL’s basis of accounting incorporates the application of FASC 805, “Business Combinations” (FASC 805) as of the date of the Merger. FASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the Merger date. DPL’s Consolidated Financial Statements and accompanying footnotes have been segregated to present pre-merger activity as the “Predecessor” Company and post-merger activity as the “Successor” Company. Purchase accounting impacts, including goodwill recognition, have been “pushed down” to DPL, resulting in the assets and liabilities of DPL being recorded at their respective fair values as of November 28, 2011 (see Note 2). These adjustments are subject to change as AES finalizes its purchase price allocation during the applicable measurement period.
As a result of the push down accounting, DPL’s Consolidated Statements of Operations subsequent to the Merger include amortization expense relating to purchase accounting adjustments and depreciation of fixed assets based upon their fair value. Therefore, the DPL financial data prior to the Merger will not generally be comparable to its financial data subsequent to the Merger. See Note 2 for additional information.
DPL remeasured the carrying amount of all of its assets and liabilities to fair value, which resulted in the recognition of approximately $2,568.1 million of goodwill. FASC 350, “Intangibles – Goodwill and Other”, requires that goodwill be tested for impairment at the reporting unit level at least annually or more frequently if impairment indicators are present. In evaluating the potential impairment of goodwill, we make estimates and assumptions about revenue, operating cash flows, capital expenditures, growth rates and discount rates based on our budgets and long term forecasts, macroeconomic projections, and current market expectations of returns on similar assets. There are inherent uncertainties related to these factors and management’s judgment in applying these factors. Generally, the fair value of a reporting unit is determined using a discounted cash flow valuation model. We could be required to evaluate the potential impairment of goodwill outside of the required annual assessment process if we experience situations, including but not limited to: deterioration in general economic conditions; operating or regulatory environment; increased competitive environment; increase in fuel costs particularly when we are unable to pass its effect to customers; negative or declining cash flows; loss of a key contract or customer particularly when we are unable to replace it on equally favorable terms; or adverse actions or assessments by a regulator. These types of events and the resulting analyses could result in goodwill impairment expense, which could substantially affect our results of operations for those periods.
As part of the purchase accounting, values were assigned to various intangible assets, including customer relationships, customer contracts and the value of our electric security plan. See Note 6 for more information.
Revenue Recognition
Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services. We consider revenue realized, or realizable, and earned when persuasive evidence of an arrangement exists, the products or services have been provided to the customer, the sales price is fixed or determinable, and collection is reasonably assured. Energy sales to customers are based on the reading of their meters that occurs on a systematic basis throughout the month. We recognize the revenues on our statements of results of operations using an accrual method for retail and other energy sales that have not yet been billed, but where electricity has been consumed. This is termed “unbilled revenues” and is a widely recognized and accepted practice for utilities. At the end of each month, unbilled revenues are determined by the estimation of unbilled energy provided to customers since the date of the last meter reading, estimated line losses, the assignment of unbilled energy provided to customer classes and the average rate per customer class.
All of the power produced at the generation plants is sold to an RTO and we in turn purchase it back from the RTO to supply our customers. These power sales and purchases are reported on a net hourly basis as revenues or purchased power on our Statements of Results of Operations. We record expenses when purchased electricity is received and when expenses are incurred, with the exception of the ineffective portion of certain power purchase contracts that are derivatives and qualify for hedge accounting. We also have certain derivative contracts that do not qualify for hedge accounting, and their unrealized gains or losses are recorded prior to the receipt of electricity.
Allowance for Uncollectible Accounts
We establish provisions for uncollectible accounts by using both historical average loss percentages to project future losses and by establishing specific provisions for known credit issues.
Property, Plant and Equipment
We record our ownership share of our undivided interest in jointly-held plants as an asset in property, plant and equipment. Property, plant and equipment are stated at cost. For regulated transmission and distribution property, cost includes direct labor and material, allocable overhead expenses and an allowance for funds used during construction (AFUDC). AFUDC represents the cost of borrowed funds and equity used to finance regulated construction projects. For non-regulated property, cost also includes capitalized interest. Capitalization of AFUDC and interest ceases at either project completion or at the date specified by regulators. AFUDC and capitalized interest was $0.5 million, $3.9 million, $3.4 million and $3.1 million in the period from November 28, 2011 through December 31, 2011, the period January 1, 2011 through November 27, 2011, and the years ended December 31, 2010 and 2009, respectively.
For unregulated generation property, cost includes direct labor and material, allocable overhead expenses and interest capitalized during construction using the provisions of GAAP relating to the accounting for capitalized interest.
For substantially all depreciable property, when a unit of property is retired, the original cost of that property less any salvage value is charged to Accumulated depreciation and amortization.
Property is evaluated for impairment when events or changes in circumstances indicate that its carrying amount may not be recoverable.
Repairs and Maintenance
Costs associated with maintenance activities, primarily power plant outages, are recognized at the time the work is performed. These costs, which include labor, materials and supplies, and outside services required to maintain equipment and facilities, are capitalized or expensed based on defined units of property.
Depreciation Study – Change in Estimate
Depreciation expense is calculated using the straight-line method, which allocates the cost of property over its estimated useful life. For DPL’s generation, transmission and distribution assets, straight-line depreciation is applied monthly on an average composite basis using group rates. In July 2010, DPL completed a depreciation rate study for non-regulated generation property based on its property, plant and equipment balances at December 31, 2009, with certain adjustments for subsequent property additions. The results of the depreciation
study concluded that many of DPL’s composite depreciation rates should be reduced due to projected useful asset lives which are longer than those previously estimated. DPL adjusted the depreciation rates for its non-regulated generation property effective July 1, 2010, resulting in a net reduction of depreciation expense. For the year ended December 31, 2011, the net reduction in depreciation expense amounted to $4.8 million ($3.1 million net of tax) compared to the prior year. On an annualized basis, the net reduction in depreciation expense is projected to be approximately $9.6 million ($6.2 million net of tax).
For DPL’s generation, transmission, and distribution assets, straight-line depreciation is applied on an average annual composite basis using group rates that approximated 5.8% in 2011, 2.6% in 2010 and 2.7% in 2009.
The following is a summary of DPL’s Property, plant and equipment with corresponding composite depreciation rates at December 31, 2011 and 2010:
Successor | Predecessor | |||||||
Composite | Composite | |||||||
$ in millions | 2011 | Rate | 2010 | Rate | ||||
Regulated: | ||||||||
Transmission | $ 189.5 | 4.8% | $ | 360.6 | 2.5% | |||
Distribution | 803.0 | 5.8% | 1,256.5 | 3.4% | ||||
General | 26.3 | 13.1% | 79.6 | 3.7% | ||||
Non-depreciable | 59.7 | N/A | 58.6 | N/A | ||||
Total regulated | $ 1,078.5 | $ | 1,755.3 | |||||
Unregulated: | ||||||||
Production / Generation | $ 1,248.0 | 6.0% | $ | 3,543.6 | 2.3% | |||
Other | 14.4 | 10.1% | 36.1 | 3.6% | ||||
Non-depreciable | 19.4 | N/A | 18.6 | N/A | ||||
Total unregulated | $ 1,281.8 | $ | 3,598.3 | |||||
Total property, plant and equipment in service | $ 2,360.3 | 5.8% | $ | 5,353.6 | 2.6% |
AROs
We recognize AROs in accordance with GAAP which requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time those obligations are incurred. Upon initial recognition of a legal liability, costs are capitalized as part of the related long-lived asset and depreciated over the useful life of the related asset. Our legal obligations associated with the retirement of our long-lived assets consists primarily of river intake and discharge structures, coal unloading facilities, loading docks, ice breakers and ash disposal facilities. Our generation AROs are recorded within other deferred credits on the balance sheets.
Estimating the amount and timing of future expenditures of this type requires significant judgment. Management routinely updates these estimates as additional information becomes available.
The balance at November 28, 2011 has been adjusted to reflect the effect of the purchase accounting.
Changes in the Liability for Generation AROs
$ in millions | ||||
2010 (Predecessor): | ||||
Balance at January 1, 2010 | $ | 16.2 | ||
Accretion expense | 0.2 | |||
Additions | 0.8 | |||
Settlements | (0.3 | ) | ||
Estimated cash flow revisions | 0.6 | |||
Balance at December 31, 2010 | 17.5 | |||
January 1, 2011 through November 27, 2011 (Predecessor): | ||||
Accretion expense | 0.8 | |||
Additions | - | |||
Settlements | (0.4 | ) | ||
Estimated cash flow revisions | 0.9 | |||
Balance at November 27, 2011 | $ | 18.8 | ||
November 28, 2011 through December 31, 2011 (Successor): | ||||
Balance at November 28, 2011 | $ | 23.6 | ||
Accretion expense | - | |||
Additions | - | |||
Settlements | (0.1 | ) | ||
Estimated cash flow revisions | 0.1 | |||
Balance at December 31, 2011 | $ | 23.6 | ||
Asset Removal Costs
We continue to record costs of removal for our regulated transmission and distribution assets through our depreciation rates and recover those amounts in rates charged to our customers. There are no known legal AROs associated with these assets. We have recorded $112.4 million and $107.9 million in estimated costs of removal at December 31, 2011 and 2010, respectively, as regulatory liabilities for our transmission and distribution property. These amounts represent the excess of the cumulative removal costs recorded through depreciation rates versus the cumulative removal costs actually incurred. See Note 4 for additional information.
Changes in the Liability for Transmission and Distribution Asset Removal Costs
$ in millions | ||||
2010 (Predecessor): | ||||
Balance at January 1, 2010 | $ | 99.1 | ||
Additions | 11.2 | |||
Settlements | (2.4 | ) | ||
Balance at December 31, 2010 | 107.9 | |||
January 1, 2011 through November 27, 2011 (Predecessor): | ||||
Additions | 8.6 | |||
Settlements | (4.3 | ) | ||
Balance at November 27, 2011 | $ | 112.2 | ||
November 28, 2011 through December 31, 2011 (Successor): | ||||
Balance at November 28, 2011 | $ | 112.2 | ||
Additions | 0.8 | |||
Settlements | (0.6 | ) | ||
Balance at December 31, 2011 | $ | 112.4 |
Regulatory Accounting
In accordance with GAAP, Regulatory assets and liabilities are recorded in the balance sheets for our regulated transmission and distribution businesses. Regulatory assets are the deferral of costs expected to be recovered in future customer rates and Regulatory liabilities represent current recovery of expected future costs.
We evaluate our Regulatory assets each period and believe recovery of these assets is probable. We have received or requested a return on certain Regulatory assets for which we are currently recovering or seeking recovery through rates. We record a return after it has been authorized in an order by a regulator. If we were required to terminate application of these GAAP provisions for all of our regulated operations, we would have to write off the amounts of all Regulatory assets and liabilities to the Statements of Results of Operations at that time. See Note 4.
Effective November 28, 2011, Regulatory assets and liabilities are presented on a current and non-current basis, depending on the term recovery is anticipated. This change was made to conform with AES’ presentation of Regulatory assets and liabilities.
Inventories
Inventories are carried at average cost and include coal, limestone, oil and gas used for electric generation, and materials and supplies used for utility operations.
Intangibles
Intangibles include emission allowances, renewable energy credits, customer relationships, customer contracts and the value of our ESP. Emission allowances are carried on a first-in, first-out (FIFO) basis for purchased emission allowances. In addition, we recorded emission allowances at their fair value as of the Merger date. Net gains or losses on the sale of excess emission allowances, representing the difference between the sales proceeds and the cost of emission allowances, are recorded as a component of our fuel costs and are reflected in Operating income when realized. During the years ended December 31, 2010 and 2009, DP&L recognized gains from the sale of emission allowances in the amounts of $0.8 million and $5.0 million, respectively. There were no gains in 2011. Beginning in January 2010, part of the gains on emission allowances were used to reduce the overall fuel rider charged to our SSO retail customers.
Customer relationships recognized as part of the purchase accounting are amortized over nine to fifteen years and customer contracts are amortized over the average length of the contracts. The ESP is amortized over one year on a straight-line basis. Emission allowances are amortized as they are used in our operations on a FIFO basis. Renewable energy credits are amortized as they are used or retired. See Note 6 for additional information.
Prior to the Merger date, emission allowances and renewable energy credits were carried as inventory. Emission allowances and renewable energy credits are now carried as intangibles in accordance with AES’ policy. The amounts for 2010 have been reclassified to reflect this change in presentation.
Income Taxes
GAAP requires an asset and liability approach for financial accounting and reporting of income taxes with tax effects of differences, based on currently enacted income tax rates, between the financial reporting and tax basis of accounting reported as deferred tax assets or liabilities in the balance sheets. Deferred tax assets are recognized for deductible temporary differences. Valuation allowances are provided against deferred tax assets unless it is more likely than not that the asset will be realized.
Investment tax credits, which have been used to reduce federal income taxes payable, are deferred for financial reporting purposes and are amortized over the useful lives of the property to which they relate. For rate-regulated operations, additional deferred income taxes and offsetting regulatory assets or liabilities are recorded to recognize that income taxes will be recoverable or refundable through future revenues.
As a result of the Merger, DPL and its subsidiaries file U.S. federal income tax returns as part of the consolidated U.S. income tax return filed by AES. Prior to the Merger, DPL and its subsidiaries filed a consolidated U.S. federal income tax return. The consolidated tax liability is allocated to each subsidiary based
on the separate return method which is specified in our tax allocation agreement and which provides a consistent, systematic and rational approach. See Note 8 for additional information.
Financial Instruments
We classify our investments in debt and equity financial instruments of publicly traded entities into different categories: held-to-maturity and available-for-sale. Available-for-sale securities are carried at fair value and unrealized gains and losses on those securities, net of deferred income taxes, are presented as a separate component of shareholders’ equity. Other-than-temporary declines in value are recognized currently in earnings. Financial instruments classified as held-to-maturity are carried at amortized cost. The cost basis for public equity security and fixed maturity investments is average cost and amortized cost, respectively.
Short-Term Investments
DPL, from time to time, utilizes VRDNs as part of its short-term investment strategy. The VRDNs are of high credit quality and are secured by irrevocable letters of credit from major financial institutions. VRDN investments have variable rates tied to short-term interest rates. Interest rates are reset every seven days and these VRDNs can be tendered for sale back to the financial institution upon notice. Although DPL’s VRDN investments have original maturities over one year, they are frequently re-priced and trade at par. We account for these VRDNs as available-for-sale securities and record them as short-term investments at fair value, which approximates cost, since they are highly liquid and are readily available to support DPL’s current operating needs.
DPL also utilizes investment-grade fixed income corporate securities in its short-term investment portfolio. These securities are accounted for as held-to-maturity investments.
Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities
DP&L collects certain excise taxes levied by state or local governments from its customers. DP&L’s excise taxes are accounted for on a net basis and recorded as a reduction in revenues in the accompanying Statements of Results of Operations.
Prior to the Merger date, certain excise and other taxes were recorded gross. Effective on the Merger date, these taxes are accounted for on a net basis and recorded as a reduction in revenues. The amounts for the period November 28, 2011 through December 31, 2011, the period January 1, 2011 through December 31, 2011, and the years ended December 31, 2010 and 2009, $4.3 million, $49.4 million, $51.7 million and $49.5 million, respectively, were reclassified to conform to this presentation.
Share-Based Compensation
We measure the cost of employee services received and paid with equity instruments based on the fair-value of such equity instrument on the grant date. This cost is recognized in results of operations over the period that employees are required to provide service. Liability awards are initially recorded based on the fair-value of equity instruments and are to be re-measured for the change in stock price at each subsequent reporting date until the liability is ultimately settled. The fair-value for employee share options and other similar instruments at the grant date are estimated using option-pricing models and any excess tax benefits are recognized as an addition to paid-in capital. The reduction in income taxes payable from the excess tax benefits is presented in the Statements of Cash Flows within Cash flows from financing activities. See Note 12 for additional information. As a result of the Merger (see Note 2), vesting of all share-based awards was accelerated as of the Merger date, and none are in existence at December 31, 2011.
Cash and Cash Equivalents
Cash and cash equivalents are stated at cost, which approximates fair value. All highly liquid short-term investments with original maturities of three months or less are considered cash equivalents.
Financial Derivatives
All derivatives are recognized as either assets or liabilities in the balance sheets and are measured at fair value. Changes in the fair value are recorded in earnings unless the derivative is designated as a cash flow hedge of a forecasted transaction or it qualifies for the normal purchases and sales exception.
We use forward contracts to reduce our exposure to changes in energy and commodity prices and as a hedge against the risk of changes in cash flows associated with expected electricity purchases. These purchases are used to hedge our full load requirements. We also hold forward sales contracts that hedge against the risk of changes in cash flows associated with power sales during periods of projected generation facility availability. We use cash flow hedge accounting when the hedge or a portion of the hedge is deemed to be highly effective and MTM accounting when the hedge or a portion of the hedge is not effective. See Note 11 for additional information.
Insurance and Claims Costs
In addition to insurance obtained from third-party providers, MVIC, a wholly-owned captive subsidiary of DPL, provides insurance coverage to us, our subsidiaries and, in some cases, our partners in commonly owned facilities we operate, for workers’ compensation, general liability, property damage, and directors’ and officers’ liability. Insurance and claims costs on the Consolidated Balance Sheets of DPL include estimated liabilities for insurance and claims costs of approximately $14.2 million and $10.1 million for 2011 and 2010, respectively. Furthermore, DP&L is responsible for claim costs below certain coverage thresholds of MVIC for the insurance coverage noted above. In addition, DP&L has estimated liabilities for medical, life, and disability reserves for claims costs below certain coverage thresholds of third-party providers. We record these additional insurance and claims costs of approximately $18.9 million and $19.0 million for 2011 and 2010, respectively, within Other current liabilities and Other deferred credits on the balance sheets. The estimated liabilities for MVIC at DPL and the estimated liabilities for workers’ compensation, medical, life and disability costs at DP&L are actuarially determined based on a reasonable estimation of insured events occurring and any payments related to those events. There is uncertainty associated with these loss estimates and actual results may differ from the estimates. Modification of these loss estimates based on experience and changed circumstances is reflected in the period in which the estimate is re-evaluated.
DPL Capital Trust II
DPL has a wholly-owned business trust, DPL Capital Trust II (the Trust), formed for the purpose of issuing trust capital securities to third-party investors. Effective in 2003, DPL deconsolidated the Trust upon adoption of the accounting standards related to variable interest entities and currently treats the Trust as a nonconsolidated subsidiary. The Trust holds mandatorily redeemable trust capital securities. The investment in the Trust, which amounts to $0.5 million and $3.6 million at December 31, 2011 and 2010, respectively, is included in Other deferred assets within Other noncurrent assets. DPL also has a note payable to the Trust amounting to $19.5 million and $142.6 million at December 31, 2011 and 2010 that was established upon the Trust’s deconsolidation in 2003. See Note 7 for additional information.
In addition to the obligations under the note payable mentioned above, DPL also agreed to a security obligation which represents a full and unconditional guarantee of payments to the capital security holders of the Trust.
Recently Adopted Accounting Standards
Comprehensive Income
In June 2011, the FASB issued ASU 2011-05 “Presentation of Comprehensive Income” (ASU 2011-05) effective for interim and annual reporting periods beginning after December 15, 2011. We adopted this ASU on January 1, 2012. This standard updates FASC 220, “Comprehensive Income.” ASU 2011-05 essentially converges US GAAP guidance on the presentation of comprehensive income with the IFRS guidance. The ASU requires the presentation of comprehensive income in one continuous financial statement or two separate but consecutive statements. Any reclassification adjustments from other comprehensive income to net income are required to be presented on the face of the Statement of Comprehensive Income. These new rules did not have a material effect on our overall results of operations, financial position or cash flows. The revised presentation has been retrospectively applied to all periods presented.
Recently Issued Accounting Standards
Fair Value Disclosures
In May 2011, the FASB issued ASU 2011-04 “Fair Value Measurements” (ASU 2011-04) effective for interim and annual reporting periods beginning after December 15, 2011. We adopted this ASU on January 1, 2012. This standard updates FASC 820, “Fair Value Measurements.” ASU 2011-04 essentially converges US GAAP guidance
on fair value with the IFRS guidance. The ASU requires more disclosures around Level 3 inputs. It also increases reporting for financial instruments disclosed at fair value but not recorded at fair value and provides clarification of blockage factors and other premiums and discounts. We do not expect these new rules to have a material effect on our overall results of operations, financial position or cash flows.
Goodwill Impairment
In September 2011, the FASB issued ASU 2011-08 “Testing Goodwill for Impairment” (ASU 2011-08) effective for interim and annual reporting periods beginning after December 15, 2011. We adopted this ASU on January 1, 2012. This standard updates FASC 350, “Intangibles-Goodwill and Other.” ASU 2011-08 allows an entity to first test Goodwill using qualitative factors to determine if it is more likely than not that the fair value of a reporting unit has been impaired, if so, then the two-step impairment test is not performed. We will incorporate these new requirements in any future goodwill impairment testing.
2. Business Combination |
On November 28, 2011, AES completed its acquisition of DPL. AES paid cash consideration of approximately $3,483.6 million. The allocation of the purchase price was based on the estimated fair value of assets acquired and liabilities assumed. In addition, Dolphin Subsidiary II, Inc. (a wholly owned subsidiary of AES) issued $1,250.0 million of debt, which, as a result of the merger of DPL and Dolphin Subsidiary II, Inc. was assumed by DPL.
The assets acquired and liabilities assumed in the acquisition were originally recorded at provisional amounts based on the preliminary purchase price allocation. We are in the process of monitoring the following additional information that could impact the purchase price allocation within the measurement period, which could be up to one year from the date of acquisition: discount rates; energy price curves, and dispatching assumptions, all of which could affect the value of the generation business property, plant and equipment; assumptions around customer switching and aggregation, which could affect the value of intangible assets; assumptions on the valuation of regulatory assets and liabilities; deferred income taxes; and the determination of reporting units. If materially different from the final amounts, such provisional amounts will be retrospectively adjusted to reflect any new information about facts and circumstances that existed at the acquisition date that, if known, would have affected the measurement of these amounts. Additionally, key input assumptions and their sensitivity to the valuation of assets acquired and liabilities assumed are continuing to be reviewed by management, which may result in requiring additional information related to these key input assumptions.
During the three months ended June 30, 2012, we recognized a decrease of $70.7 million in the provisional value of property, plant and equipment and a related decrease of $37.5 million in the provisionally recognized deferred tax liabilities as a result of refined information associated with certain contractual arrangements, growth and ancillary revenue assumptions. Additionally, we recognized a decrease of $19.1 million related to certain customer contracts of DPLER and other intangibles and a related decrease of $6.7 million in the provisionally recognized deferred tax liabilities due to refined market and contractual information obtained during this quarter. These purchase price adjustments increased the provisionally recognized goodwill by $78.8 million and have been reflected retrospectively as of December 31, 2011 in the accompanying Condensed Consolidated Balance Sheets. The effect on net income related to these adjustments for the twelve months ending December 31, 2012 will be an increase of approximately $13.3 million. The effect on net income for the period November 28, 2011 through December 31, 2011 was not material.
Estimated fair value of assets acquired and liabilities assumed as of the Merger date are as follows:
$ in millions | Current purchase price allocation | Preliminary purchase price allocation | ||||||
Cash | $ | 116.4 | $ | 116.4 | ||||
Accounts receivable | 277.6 | 277.6 | ||||||
Inventory | 123.7 | 123.7 | ||||||
Other current assets | 41.0 | 41.0 | ||||||
Property, plant and equipment | 2,477.8 | 2,548.5 | ||||||
Intangible assets subject to amortization | 147.2 | 166.3 | ||||||
Intangible assets - indefinite-lived | 5.0 | 5.0 | ||||||
Regulatory assets | 201.7 | 201.1 | ||||||
Other non-current assets | 58.3 | 58.3 | ||||||
Current liabilities | (405.1 | ) | (400.2 | ) | ||||
Debt | (1,255.1 | ) | (1,255.1 | ) | ||||
Deferred taxes | (514.5 | ) | (558.2 | ) | ||||
Regulatory liabilities | (117.0 | ) | (117.0 | ) | ||||
Other non-current liabilities | (223.1 | ) | (194.7 | ) | ||||
Redeemable preferred stock | (18.4 | ) | (18.4 | ) | ||||
Net identifiable assets acquired | 915.5 | 994.3 | ||||||
Goodwill | 2,568.1 | 2,489.3 | ||||||
Net assets acquired | $ | 3,483.6 | $ | 3,483.6 |
The carrying values of the majority of regulated assets and liabilities were determined to be stated at their estimate fair values at the Merger date based on a conclusion that individual assets are subject to regulation by the PUCO and the FERC. As a result, the future cash flows associated with the assets are limited to the carrying value plus a return, and management believes that a market participant would not expect to recover any more or less than the carrying value. Furthermore, management believes that the current rate of return on regulated assets is consistent with an amount that market participants would expect. FASC 805 requires that the beginning balance of fixed depreciable assets be shown net, with no accumulated amortization recorded, at the date of the Merger.
Property, plant and equipment were valued based on the discounted value of the estimated future cash flows to be generated from such assets.
Intangible assets include the fair value of customer relationships, customer contracts and DP&L’s ESP based on a combination of the income approach, the market based approach and the cost approach.
The fair value of inventory consists primarily of two components: materials and supplies; and fuel and limestone. The estimated fair value at the Merger date was established using a variety of approaches to estimate the market price. The carrying value of fuel inventory was adjusted to its fair value by applying market cost at the Merger date.
Energy derivative contracts were reassessed and revalued at the Merger date based on forward market prices and forecasted energy requirements. The fair value assigned to the power contracts was determined using an income approach comparing the contract rate to the market rate for power over the remaining period of the contracts incorporating nonperformance risk. Management also incorporated certain assumptions related to quantities and market presentation that it believes market participants would make in the valuation. The fair value of the power contracts will be amortized as the contracts settle.
Other regulatory assets are costs that are being recovered or will be recovered through the ratemaking process and are valued at their expected recoverable amount.
The fair value assigned to long-term debt was determined by a third party pricing service’s quoted price.
Redeemable preferred stock was valued based on the last price paid by a third party.
The Merger triggered a new basis of accounting for DPL for the postretirement benefit plans sponsored by DPL under FASC 805 which required remeasuring plan liabilities without the five year smoothing of market-related asset gains and losses.
During the periods January 1, 2011 through November 27, 2011 and November 28, 2011 through December 31, 2011, DPL incurred pre-tax merger costs of $37.9 million and $15.7 million, respectively, primarily related to legal fees, transaction advisory services and change of control provisions. DPL does not anticipate significant merger related costs in 2012.
As a result of the Merger, DPL reclassified emission allowances and renewable energy credits to intangible assets and records certain excise and other taxes net as a reduction of revenue, consistent with AES’ policies. All material prior period amounts have been reclassified to conform to this presentation.
3. Supplemental Financial Information |
DPL Inc. | Successor | Predecessor | |||||||
At | At | ||||||||
December 31, | December 31, | ||||||||
$ in millions | 2011 | 2010 | |||||||
Accounts receivable, net: | |||||||||
Unbilled revenue | $ | 72.4 | $ | 84.5 | |||||
Customer receivables | 113.2 | 113.9 | |||||||
Amounts due from partners in jointly-owned plants | 29.2 | 7.0 | |||||||
Coal sales | 1.0 | 4.0 | |||||||
Other | 4.4 | 7.0 | |||||||
Provision for uncollectible accounts | (1.1 | ) | (0.9 | ) | |||||
Total accounts receivable, net | $ | 219.1 | $ | 215.5 | |||||
Inventories, at average cost: | |||||||||
Fuel and limestone | $ | 84.2 | $ | 73.2 | |||||
Plant materials and supplies | 39.8 | 38.8 | |||||||
Other | 1.8 | 0.6 | |||||||
Total inventories, at average cost | $ | 125.8 | $ | 112.6 |
4. Regulatory Matters |
In accordance with GAAP, regulatory assets and liabilities are recorded in the consolidated balance sheets for our regulated electric transmission and distribution businesses. Regulatory assets are the deferral of costs expected to be recovered in future customer rates and regulatory liabilities represent current recovery of expected future costs or gains probable of recovery being reflected in future rates.
We evaluate our regulatory assets each period and believe recovery of these assets is probable. We have received or requested a return on certain regulatory assets for which we are currently recovering or seeking recovery through rates. We record a return after it has been authorized in an order by a regulator.
Regulatory assets and liabilities are classified as current or non-current based on the term in which recovery is expected. Amounts at December 31, 2010 were reclassified to conform to the 2011 presentation.
The following table presents DPL’s regulatory assets and liabilities:
Successor | Predecessor | ||||||||||||||||
Type of | Amortization | December 31, | December 31, | ||||||||||||||
$ in millions | Recovery (a) | Through | 2011 | 2010 | |||||||||||||
Current Regulatory Assets: | |||||||||||||||||
TCRR, transmission, ancillary and other PJM-related costs | F | Ongoing | $ | 4.7 | $ | 14.5 | |||||||||||
Power plant emission fees | C | Ongoing | 4.8 | 6.6 | |||||||||||||
Electric Choice systems costs | F | 2011 | - | 0.9 | |||||||||||||
Fuel and purchased power recovery costs | C | Ongoing | 11.3 | - | |||||||||||||
Total current regulatory assets | $ | 20.8 | $ | 22.0 | |||||||||||||
Non-current Regulatory Assets: | |||||||||||||||||
Deferred recoverable income taxes | B/C | Ongoing | $ | 24.1 | $ | 29.9 | |||||||||||
Pension benefits | C | Ongoing | 92.1 | 81.1 | |||||||||||||
Unamortized loss on reacquired debt | C | Ongoing | 13.0 | 14.3 | |||||||||||||
Regional transmission organization costs | D | 2014 | 4.1 | 5.5 | |||||||||||||
Deferred storm costs - 2008 | D | 17.9 | 16.9 | ||||||||||||||
CCEM smart grid and advanced metering infrastructure costs | D | 6.6 | 6.6 | ||||||||||||||
CCEM energy efficiency program costs | F | Ongoing | 8.8 | 4.8 | |||||||||||||
Consumer education campaign | D | 3.0 | 3.0 | ||||||||||||||
Retail settlement system costs | D | 3.1 | 3.1 | ||||||||||||||
Other costs | 5.1 | 1.8 | |||||||||||||||
Total non-current regulatory assets | $ | 177.8 | $ | 167.0 | |||||||||||||
Current Regulatory Liabilities: | |||||||||||||||||
Fuel and purchased power recovery costs | C | Ongoing | - | 10.0 | |||||||||||||
Other | C | Ongoing | 0.5 | - | |||||||||||||
Total current regulatory liabilities | $ | 0.5 | $ | 10.0 | |||||||||||||
Non-current Regulatory Liabilities: | |||||||||||||||||
Estimated costs of removal - regulated property | $ | 112.4 | $ | 107.9 | |||||||||||||
Postretirement benefits | 6.2 | 6.1 | |||||||||||||||
Total non-current regulatory liabilities | $ | 118.6 | $ | 114.0 |
(a) | B – Balance has an offsetting liability resulting in no effect on rate base. |
C – Recovery of incurred costs without a rate of return.
D – Recovery not yet determined, but is probable of occurring in future rate proceedings.
F – Recovery of incurred costs plus rate of return.
Regulatory Assets
TCRR, transmission, ancillary and other PJM-related costs represent the costs related to transmission, ancillary service and other PJM-related charges that have been incurred as a member of PJM. On an annual basis, retail rates are adjusted to true-up costs with recovery in rates.
Power plant emission fees represent costs paid to the State of Ohio since 2002. As part of the fuel factor settlement agreement in November 2011, these costs are being recovered through the fuel factor.
Electric Choice systems costs represent costs incurred to modify the customer billing system for unbundled customer rates and electric choice utility bills relative to other generation suppliers and information reports provided to the state administrator of the low-income payment program. In March 2006, the PUCO issued an order that approved our tariff as filed. We began collecting this rider immediately and have recovered all costs.
Fuel and purchased power recovery costs represent prudently incurred fuel, purchased power, derivative, emission and other related costs which will be recovered from or returned to customers in the future through the operation of the fuel and purchased power recovery rider. The fuel and purchased power recovery rider fluctuates based on actual costs and recoveries and is modified at the start of each seasonal quarter. DP&L implemented the fuel and purchased power recovery rider on January 1, 2010. As part of the PUCO approval process, an outside auditor is hired to review fuel costs and the fuel procurement process. On October 6, 2011, DP&L and all of the active participants in this proceeding reached a Stipulation and Recommendation that resolves the majority of the issues raised related to the fuel audit. In November 2011, DP&L recorded a $25 million pretax ($16 million net of tax) adjustment as a result of the approval of the fuel settlement agreement by the PUCO. The adjustment was due to the reversal of a provision recorded in accordance with the regulatory accounting rules. An audit of 2011 costs is currently ongoing. The outcome of that audit is uncertain.
Deferred recoverable income taxes represent deferred income tax assets recognized from the normalization of flow through items as the result of tax benefits previously provided to customers. This is the cumulative flow through benefit given to regulated customers that will be collected from them in future years. Since currently existing temporary differences between the financial statements and the related tax basis of assets will reverse in subsequent periods, these deferred recoverable income taxes will decrease over time.
Pension benefits represent the qualifying FASC 715 “Compensation – Retirement Benefits” costs of our regulated operations that for ratemaking purposes are deferred for future recovery. We recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income (OCI), the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. This regulatory asset represents the regulated portion that would otherwise be charged as a loss to OCI.
Unamortized loss on reacquired debt represents losses on long-term debt reacquired or redeemed in prior periods. These costs are being amortized over the lives of the original issues in accordance with FERC and PUCO rules.
Regional transmission organization costs represent costs incurred to join an RTO. The recovery of these costs will be requested in a future FERC rate case. In accordance with FERC precedence, we are amortizing these costs over a 10-year period that began in 2004 when we joined the PJM RTO.
Deferred storm costs – 2008 relate to costs incurred to repair the damage caused by hurricane force winds in September 2008, as well as other major 2008 storms. On January 14, 2009, the PUCO granted DP&L the authority to defer these costs with a return until such time that DP&L seeks recovery in a future rate proceeding.
CCEM smart grid and AMI costs represent costs incurred as a result of studying and developing distribution system upgrades and implementation of AMI. On October 19, 2010, DP&L elected to withdraw its case pertaining to the Smart Grid and AMI programs. The PUCO accepted the withdrawal in an order issued on January 5, 2011. The PUCO also indicated that it expects DP&L to continue to monitor other utilities’ Smart Grid and AMI programs and to explore the potential benefits of investing in Smart Grid and AMI programs and that DP&L will, when appropriate, file new Smart Grid and/or AMI business cases in the future. We plan to file to recover these deferred costs in a future regulatory rate proceeding. Based on past PUCO precedent, we believe these costs are probable of future recovery in rates.
CCEM energy efficiency program costs represent costs incurred to develop and implement various new customer programs addressing energy efficiency. These costs are being recovered through an energy efficiency rider that began July 1, 2009 and is subject to a two-year true-up for any over/under recovery of costs. The two-year true-up was approved by the PUCO and a new rate was set.
Consumer education campaign represents costs for consumer education advertising regarding electric deregulation and its related rate case.
Retail settlement system costs represent costs to implement a retail settlement system that reconciles the energy a CRES supplier delivers to its customers and what its customers actually use. Based on case precedent in other utilities’ cases, the costs are recoverable through DP&L’s next transmission rate case.
Other costs primarily include RPM capacity, other PJM and rate case costs and alternative energy costs that are or will be recovered over various periods.
Regulatory Liabilities
Estimated costs of removal – regulated property reflect an estimate of amounts collected in customer rates for costs that are expected to be incurred in the future to remove existing transmission and distribution property from service when the property is retired.
Postretirement benefits represent the qualifying FASC 715 “Compensation – Retirement Benefits” gains related to our regulated operations that, for ratemaking purposes, are probable of being reflected in future rates. We recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of OCI, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. This regulatory liability represents the regulated portion that would otherwise be reflected as a gain to OCI.
5. Ownership of Coal-fired Facilities |
DP&L and certain other Ohio utilities have undivided ownership interests in seven coal-fired electric generating facilities and numerous transmission facilities. Certain expenses, primarily fuel costs for the generating units, are allocated to the owners based on their energy usage. The remaining expenses, investments in fuel inventory, plant materials and operating supplies, and capital additions are allocated to the owners in accordance with their respective ownership interests. As of December 31, 2011, DP&L had $48.0 million of construction work in process at such facilities. DP&L’s share of the operating cost of such facilities is included within the corresponding line in the Statements of Results of Operations and DP&L’s share of the investment in the facilities is included within Total net property, plant and equipment in the Balance Sheets. Each joint owner provides their own financing for their share of the operations and capital expenditures of the jointly-owned plant.
DP&L’s undivided ownership interest in such facilities as well as our wholly-owned coal fired Hutchings plant at December 31, 2011, is as follows:
DP&L Investment | |||||||||||||||||||||
DP&L Share | (adjusted to fair value at Merger date) | ||||||||||||||||||||
SCR and FGD | |||||||||||||||||||||
Equipment | |||||||||||||||||||||
Summer | Construction | Installed | |||||||||||||||||||
Production | Gross Plant | Accumulated | Work in | and In | |||||||||||||||||
Ownership | Capacity | In Service | Depreciation | Process | Service | ||||||||||||||||
(%) | (MW) | ($ in millions) | ($ in millions) | ($ in millions) | (Yes/No) | ||||||||||||||||
Production Units: | |||||||||||||||||||||
Beckjord Unit 6 | 50.0 | 207 | $ | - | $ | - | $ | - | No | ||||||||||||
Conesville Unit 4 | 16.5 | 129 | 43 | - | 2 | Yes | |||||||||||||||
East Bend Station | 31.0 | 186 | - | - | 2 | Yes | |||||||||||||||
Killen Station | 67.0 | 402 | 296 | - | 4 | Yes | |||||||||||||||
Miami Fort Units 7 and 8 | 36.0 | 368 | 216 | 1 | 2 | Yes | |||||||||||||||
Stuart Station | 35.0 | 808 | 174 | 1 | 14 | Yes | |||||||||||||||
Zimmer Station | 28.1 | 365 | 123 | 2 | 24 | Yes | |||||||||||||||
Transmission (at varying percentages) | 34 | - | - | ||||||||||||||||||
Total | 2,465 | $ | 886 | $ | 4 | $ | 48 | ||||||||||||||
Wholly-owned production unit: | |||||||||||||||||||||
Hutchings Station | 100.0 | 365 | $ | - | $ | - | $ | 2 | No |
Currently, our coal-fired generation units at Hutchings and Beckjord do not have the SCR and FGD emission-control equipment installed. DP&L owns 100% of the Hutchings plant and has a 50% interest in Beckjord Unit 6. On July 15, 2011, Duke Energy, a co-owner at the Beckjord Unit 6 facility, filed their Long-term Forecast Report with the PUCO. The plan indicated that Duke Energy plans to cease production at the Beckjord Station, including our jointly-owned Unit 6, in December 2015. This was followed by a notification by Duke Energy to PJM, dated February 1, 2012, of a planned April 1, 2015 deactivation of this unit. Beckjord Unit 6 was valued at zero at the Merger date. We are considering options for Hutchings Station, but have not yet made a final decision. We do not believe that any accruals are needed related to the Hutchings Station.
DPL revalued DP&L’s investment in the above plants at the estimated fair value for each plant at the Merger date. These values were updated in June 2012 to reflect additional information obtained regarding the cash flows of certain plants. See Note 2 for more information.
6. Goodwill and Other Intangible Assets |
Goodwill at November 28, 2011 represents the value assigned at the Merger date. DPL had no goodwill recorded at December 31, 2010 and during the January 1, 2011 through November 27, 2011 predecessor period. Goodwill as of November 28, 2011 and December 31, 2011 was $2,568.1 million. DPL did not recognize any impairment losses related to goodwill during 2011.
The following tables summarize the balances comprising Intangible assets as of December 31, 2011:
$ in millions | December 31, 2011 | |||||||||||
Gross | Accumulated | Net | ||||||||||
Balance | Amortization | Balance | ||||||||||
Subject to Amortization | ||||||||||||
Electric Security Plan (a) | $ | 87.0 | $ | (8.6 | ) | $ | 78.4 | |||||
Customer contracts (b) | 28.0 | (3.0 | ) | 25.0 | ||||||||
Customer relationships (c) | 31.8 | (0.5 | ) | 31.3 | ||||||||
Other (d) | 3.9 | (1.2 | ) | 2.7 | ||||||||
150.7 | (13.3 | ) | 137.4 | |||||||||
Not subject to Amortization | ||||||||||||
Tradmark/Trade name (e) | 5.0 | - | 5.0 | |||||||||
Total intangibles | $ | 155.7 | $ | (13.3 | ) | $ | 142.4 |
The following table summarizes, by category, intangible assets acquired during the year ended December 31, 2011:
$ in millions | Amount | Subject to Amortization/ Indefinite-lived | Weighted Average Amortization Period (years) | Amortization Method | ||||||||||
Electric security plan (a)(f) | $ | 87.0 | Subject to amortization | 1 | Other | |||||||||
Customer contracts (b)(f) | 28.0 | Subject to amortization | 3 | Other | ||||||||||
Customer relationships (c) | 31.8 | Subject to amortization | 15 | Straight line | ||||||||||
Other (d) | 1.2 | Subject to amortization | Various | As Utilized | ||||||||||
Trademark/Trade name (e) | 5.0 | Indefinite-lived | N/A | N/A | ||||||||||
$ | 153.0 |
(a) | Represents the value of DP&L’s Electric Security Plan which is a rate plan for the supply and pricing of electric generation services. It provides a level of price stability to consumers of electricity compared to market-based electricity prices. |
(b) | Represents above market contracts that DPLER has with third party customers existing as of the Merger date. |
(c) | Represents relationships DPLER has with third party customers as of the Merger date, where DPLER has regular contact with the customer, and the customer has the ability to make direct contract with DPLER. |
(d) | Consists of various intangible assets including renewable energy credits, emission allowances, and other intangibles, none of which are individually significant. |
(e) | Trademark/Trade name represents the value assigned to the trade name of DPLER. |
(f) | The amortization method used reflects the pattern in which the economic benefits of the intangible asset are consumed. Amortization of these intangible assets is shown as a reduction within gross margin on our Consolidated Statements of Results of Operations. |
Most of the intangible assets acquired during the period disclosed above arose from the acquisition of DPL by AES (see Note 2 for more information). An immaterial amount of intangible assets was acquired by DPL through the acquisition of MC Squared Energy Services on February 28, 2011.
The following table summarizes the amortization expense, broken down by intangible asset category for 2012 through 2016:
Estimated amortization expense | ||||||||||||||||||||
$ in millions | 2012 | 2013 | 2014 | 2015 | 2016 | |||||||||||||||
Electric security plan | $ | 78.4 | $ | - | $ | - | $ | - | $ | - | ||||||||||
Customer contracts | 17.1 | 6.8 | 1.1 | - | - | |||||||||||||||
Customer relationships | 2.5 | 2.5 | 2.5 | 2.5 | 2.2 | |||||||||||||||
Other | - | 0.3 | 0.2 | 0.2 | - | |||||||||||||||
$ | 98.0 | $ | 9.6 | $ | 3.8 | $ | 2.7 | $ | 2.2 |
7. Debt Obligations |
Long-term Debt | Successor | Predecessor | |||||||
December 31, | December 31, | ||||||||
$ in millions | 2011 | 2010 | |||||||
First mortgage bonds maturing in October 2013 - 5.125% | $ | 503.6 | $ | 470.0 | |||||
Pollution control series maturing in January 2028 - 4.70% | 36.1 | 35.3 | |||||||
Pollution control series maturing in January 2034 - 4.80% | 179.6 | 179.1 | |||||||
Pollution control series maturing in September 2036 - 4.80% | 96.2 | 100.0 | |||||||
Pollution control series maturing in November 2040 - | |||||||||
variable rates: 0.06% - 0.32% and 0.16% - 0.36% (a) | 100.0 | 100.0 | |||||||
U.S. Government note maturing in February 2061 - 4.20% | 18.5 | - | |||||||
934.0 | 884.4 | ||||||||
Obligation for capital lease | 0.4 | 0.1 | |||||||
Unamortized debt discount | - | (0.5 | ) | ||||||
Total long-term debt at subsidiary | 934.4 | 884.0 | |||||||
Bank Term Loan - variable rates: 1.48% - 4.25% (b) | 425.0 | - | |||||||
Senior unsecured bonds maturing October 2016 - 6.50% | 450.0 | - | |||||||
Senior unsecured bonds maturing October 2021 - 7.25% | 800.0 | - | |||||||
Note to DPL Capital Trust II maturing in September 2031 - 8.125% | 19.5 | 142.6 | |||||||
Total long-term debt | $ | 2,628.9 | $ | 1,026.6 | |||||
Current portion - Long-term Debt | Successor | Predecessor | |||||||
December 31, | December 31, | ||||||||
$ in millions | 2011 | 2010 | |||||||
U.S. Government note maturing in February 2061 - 4.20% | $ | 0.1 | $ | - | |||||
Obligation for capital lease | 0.3 | 0.1 | |||||||
Total current portion - long-term debt at subsidiary | 0.4 | 0.1 | |||||||
Senior notes maturing in September 2011 - 6.875% | - | 297.4 | |||||||
Total current portion - long-term debt | $ | 0.4 | $ | 297.5 |
(a) Range of interest rates for the twelve months ended December 31, 2011 and December 31, 2010, respectively. | |||||||||
(b) Range of interest rates since the loan was drawn in August 2011. |
The presentation above for the Successor is based on the revaluation of the debt at the Merger date.
At December 31, 2011, maturities of long-term debt, including capital lease obligations, are summarized as follows:
$ in millions | DPL | |||
Due within one year | $ | 0.4 | ||
Due within two years | 470.4 | |||
Due within three years | 425.2 | |||
Due within four years | 0.1 | |||
Due within five years | 450.1 | |||
Thereafter | 1,252.9 | |||
2,599.1 | ||||
Unamortized adjustments to market | ||||
value from purchase accounting | 30.2 | |||
Total long-term debt | $ | 2,629.3 |
Premium or discount recognized at the Merger date are amortized over the life of the debt using the effective interest method.
On November 21, 2006, DP&L entered into a $220 million unsecured revolving credit agreement. This agreement was terminated by DP&L on August 29, 2011.
On December 4, 2008, the OAQDA issued $100 million of collateralized, variable rate Revenue Refunding Bonds Series A and B due November 1, 2040. In turn, DP&L borrowed these funds from the OAQDA and issued corresponding First Mortgage Bonds to support repayment of the funds. The payment of principal and interest on each series of the bonds when due is backed by a standby letter of credit issued by JPMorgan Chase Bank, N.A. This letter of credit facility, which expires in December 2013, is irrevocable and has no subjective acceleration clauses. Fees associated with this letter of credit facility were not material during the years ended December 31, 2011 and 2010, respectively.
On April 20, 2010, DP&L entered into a $200 million unsecured revolving credit agreement with a syndicated bank group. This agreement is for a three year term expiring on April 20, 2013 and provides DP&L with the ability to increase the size of the facility by an additional $50 million. DP&L had no outstanding borrowings under this credit facility at December 31, 2011. Fees associated with this revolving credit facility were not material during the period between April 20, 2010 and December 31, 2011. This facility also contains a $50 million letter of credit sublimit. As of December 31, 2011, DP&L had no outstanding letters of credit against the facility.
On February 23, 2011, DPL purchased $122.0 million principal amount of DPL Capital Trust II 8.125% capital securities in a privately negotiated transaction. As part of this transaction, DPL paid a $12.2 million, or 10%, premium. Debt issuance costs and unamortized debt discount totaling $3.1 million were also recognized in February 2011 associated with this transaction.
On March 1, 2011, DP&L completed the purchase of $18.7 million of electric transmission and distribution assets from the federal government that are located at the Wright-Patterson Air Force Base. DP&L financed the acquisition of these assets with a note payable to the federal government that is payable monthly over 50 years and bears interest at 4.2% per annum.
On August 24, 2011, DP&L entered into a $200 million unsecured revolving credit agreement with a syndicated bank group. This agreement is for a four year term expiring on August 24, 2015 and provides DP&L with the ability to increase the size of the facility by an additional $50 million. DP&L had no outstanding borrowings under this credit facility at December 31, 2011. Fees associated with this revolving credit facility were not material during the five months ended December 31, 2011. This facility also contains a $50 million letter of credit sublimit. As of December 31, 2011, DP&L had no outstanding letters of credit against the facility.
On August 24, 2011, DPL entered into a $125 million unsecured revolving credit agreement with a syndicated bank group. This agreement is for a three year term expiring on August 24, 2014. DPL had no outstanding borrowings under this credit facility at December 31, 2011. Fees associated with this revolving credit facility were not material during the five months ended December 31, 2011. This facility may also be used to issue letters of credit up to the $125 million limit. As of December 31, 2011, DPL had no outstanding letters of credit against the facility.
On August 24, 2011, DPL entered into a $425 million unsecured term loan agreement with a syndicated bank group. This agreement is for a three year term expiring on August 24, 2014. DPL has borrowed the entire $425 million available under the facility at December 31, 2011. Fees associated with this term loan were not material during the five months ended December 31, 2011.
On September 1, 2011 DPL retired $297.4 million of 6.875% senior unsecured notes that had matured.
In connection with the closing of the Merger (see Note 2), DPL assumed $1.25 billion of debt that Dolphin Subsidiary II, Inc., a subsidiary of AES, issued on October 3, 2011 to finance a portion of the merger. The $1.25 billion was issued in two tranches. The first tranche was $450 million of five year senior unsecured notes issued at 6.50% maturing on October 15, 2016. The second tranche was $800 million of ten year senior unsecured notes issued at 7.25% maturing on October 15, 2021.
Substantially all property, plant and equipment of DP&L is subject to the lien of the mortgage securing DP&L’s First and Refunding Mortgage, dated October 1, 1935, with the Bank of New York Mellon as Trustee.
8. Income Taxes |
DPL’s components of income tax expense were as follows:
Successor | Predecessor | ||||||||||||||||
November 28, 2011 | January 1, 2011 | ||||||||||||||||
through | through | Years ended December 31, | |||||||||||||||
$ in millions | December 31, 2011 | November 27, 2011 | 2010 | 2009 | |||||||||||||
Computation of Tax Expense | |||||||||||||||||
Federal income tax expense / (benefit) (a) | $ | (2.0 | ) | $ | 88.4 | $ | 151.7 | $ | 119.9 | ||||||||
Increases (decreases) in tax resulting from: | |||||||||||||||||
State income taxes, net of federal effect | 0.1 | 3.8 | 2.4 | 0.9 | |||||||||||||
Depreciation of AFUDC - Equity | (0.3 | ) | (2.9 | ) | (2.2 | ) | (2.0 | ) | |||||||||
Investment tax credit amortized | (0.2 | ) | (2.3 | ) | (2.8 | ) | (2.8 | ) | |||||||||
Section 199 - domestic production deduction | - | (3.6 | ) | (9.1 | ) | (4.6 | ) | ||||||||||
Non-deductible merger costs | 0.1 | 6.0 | - | - | |||||||||||||
Non-deductible merger-related compensation | 3.5 | - | - | - | |||||||||||||
Derivatives | (0.1 | ) | - | - | - | ||||||||||||
Compensation and benefits | - | 13.8 | 0.4 | (0.7 | ) | ||||||||||||
Income not subject to tax | (0.6 | ) | - | - | - | ||||||||||||
Other, net (b) | 0.1 | (1.2 | ) | 2.6 | 1.8 | ||||||||||||
Total tax expense | $ | 0.6 | $ | 102.0 | $ | 143.0 | $ | 112.5 | |||||||||
Components of Tax Expense | |||||||||||||||||
Federal - Current | $ | 0.4 | $ | 53.2 | $ | 84.8 | $ | (84.4 | ) | ||||||||
State and Local - Current | 0.4 | 0.9 | 1.1 | (1.8 | ) | ||||||||||||
Total Current | $ | 0.8 | $ | 54.1 | $ | 85.9 | $ | (86.2 | ) | ||||||||
Federal - Deferred | $ | (0.2 | ) | $ | 43.2 | $ | 55.9 | $ | 196.0 | ||||||||
State and Local - Deferred | - | 4.7 | 1.2 | 2.7 | |||||||||||||
Total Deferred | $ | (0.2 | ) | $ | 47.9 | $ | 57.1 | $ | 198.7 | ||||||||
Total tax expense | $ | 0.6 | $ | 102.0 | $ | 143.0 | $ | 112.5 | |||||||||
Components of Deferred Tax Assets and Liabilities | |||||||||||||||||
Successor | Predecessor | ||||||||||||||||
December 31, | December 31, | ||||||||||||||||
$ in millions | 2011 | 2010 | |||||||||||||||
Net Noncurrent Assets / (Liabilities) | |||||||||||||||||
Depreciation / property basis | $ | (453.2 | ) | $ | (618.6 | ) | |||||||||||
Income taxes recoverable | (8.6 | ) | (10.3 | ) | |||||||||||||
Regulatory assets | (25.1 | ) | (12.4 | ) | |||||||||||||
Investment tax credit | 10.5 | 11.3 | |||||||||||||||
Intangibles | (50.8 | ) | - | ||||||||||||||
Compensation and employee benefits | (7.9 | ) | 21.0 | ||||||||||||||
Long-term debt | 10.3 | - | |||||||||||||||
Other (c) | 19.1 | (14.1 | ) | ||||||||||||||
Net noncurrent (liabilities) | $ | (505.7 | ) | $ | (623.1 | ) | |||||||||||
Net Current Assets / (Liabilities) (d) | |||||||||||||||||
Other | $ | 0.8 | $ | (1.1 | ) | ||||||||||||
Net current assets | $ | 0.8 | $ | (1.1 | ) |
(a) | The statutory tax rate of 35% was applied to pre-tax earnings from continuing operations. |
(b) | Includes benefits of $2.3 million and $0.3 million, and an expense of $2.0 million in 2011, 2010 and 2009, respectively, of income tax related to adjustments from prior years. |
(c) | The Other noncurrent liabilities caption includes deferred tax assets of $15.4 million in 2011 and $13.1 million in 2010 related to state and local tax net operating loss carryforwards, net of related valuation allowances of $6.7 million in 2011 and $13.1 million in 2010. These net operating loss carryforwards expire from 2017 to 2026. |
(d) | Amounts are included within Other prepayments and current assets on the Consolidated Balance Sheets of DPL. |
The following table presents the tax expense / (benefit) related to pensions, postretirement benefits, cash flow hedges and financial instruments that were credited to Accumulated other comprehensive loss.
Successor | Predecessor | ||||||||||||||||
November 28, 2011 | January 1, 2011 | ||||||||||||||||
through | through | Years ended December 31, | |||||||||||||||
$ in millions | December 31, 2011 | November 27, 2011 | 2010 | 2009 | |||||||||||||
Expense / (benefit) | $ | (1.2 | ) | $ | (33.2 | ) | $ | 5.8 | $ | (1.7 | ) |
Accounting for Uncertainty in Income Taxes
We apply the provisions of GAAP relating to the accounting for uncertainty in income taxes. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
$ in millions | ||||
2009 (Predecessor): | ||||
Balance at January 1, 2009 | $ | 1.9 | ||
Tax positions taken during prior periods | - | |||
Tax positions taken during current period | 20.6 | |||
Settlement with taxing authorities | (3.2 | ) | ||
Lapse of applicable statute of limitations | - | |||
Balance at December 31, 2009 | 19.3 | |||
2010 (Predecessor): | ||||
Tax positions taken during prior periods | (0.4 | ) | ||
Tax positions taken during current period | - | |||
Settlement with taxing authorities | 0.3 | |||
Lapse of applicable statute of limitations | 0.2 | |||
Balance at December 31, 2010 | 19.4 | |||
January 1, 2011 through November 27, 2011 (Predecessor): | ||||
Tax positions taken during prior periods | 2.0 | |||
Tax positions taken during current period | 3.5 | |||
Settlement with taxing authorities | - | |||
Lapse of applicable statute of limitations | - | |||
Balance at November 27, 2011 | $ | 24.9 | ||
November 28, 2011 through December 31, 2011 (Successor): | ||||
Balance at November 28, 2011 | $ | 24.9 | ||
Tax positions taken during prior periods | - | |||
Tax positions taken during current period | 0.1 | |||
Settlement with taxing authorities | - | |||
Lapse of applicable statute of limitations | - | |||
Balance at December 31, 2011 | $ | 25.0 |
Of the December 31, 2011 balance of unrecognized tax benefits, $26.1 million is due to uncertainty in the timing of deductibility offset by $1.1 million of unrecognized tax liabilities that would affect the effective tax rate.
We recognize interest and penalties related to unrecognized tax benefits in Income tax expense. The following table represents the amounts accrued as well as the expense / (benefit) recorded as of and for the periods noted below:
Amounts in Balance Sheet | Successor | Predecessor | |||||||||||||||
December 31, | December 31, | December 31, | |||||||||||||||
$ in millions | 2011 | 2010 | 2009 | ||||||||||||||
Liability / (asset) | $ | 0.9 | $ | 0.3 | $ | (1.0 | ) | ||||||||||
Amounts in Statement of Operations | Successor | Predecessor | |||||||||||||||
November 28, 2011 | January 1, 2011 | ||||||||||||||||
through | through | Years ended December 31, | |||||||||||||||
$ in millions | December 31, 2011 | November 27, 2011 | 2010 | 2009 | |||||||||||||
Expense / (benefit) | $ | - | $ | 0.6 | $ | 0.4 | $ | (0.1 | ) |
Following is a summary of the tax years open to examination by major tax jurisdiction:
U.S. Federal – 2007 and forward
State and Local – 2005 and forward
None of the unrecognized tax benefits are expected to significantly increase or decrease within the next twelve months.
The Internal Revenue Service began an examination of our 2008 Federal income tax return during the second quarter of 2010. The examination is still ongoing and we do not expect the results of this examination to have a material effect on our financial condition, results of operations and cash flows.
9. Pension and Postretirement Benefits |
DP&L sponsors a traditional defined benefit pension plan for most of the employees of DPL and its subsidiaries. For collective bargaining employees, the defined benefits are based on a specific dollar amount per year of service. For all other employees (management employees), the traditional defined benefit pension plan is based primarily on compensation and years of service. As of December 31, 2010, this traditional pension plan was closed to new management employees. A participant is 100% vested in all amounts credited to his or her account upon the completion of five vesting years, as defined in The Dayton Power and Light Company Retirement Income Plan, or the participant’s death or disability. If a participant’s employment is terminated, other than by death or disability, prior to such participant becoming 100% vested in his or her account, the account shall be forfeited as of the date of termination.
Almost all management employees beginning employment on or after January 1, 2011 participate in a cash balance pension plan. Similar to the traditional pension plan for management employees, the cash balance benefits are based on compensation and years of service. A participant shall become 100% vested in all amounts credited to his or her account upon the completion of three vesting years, as defined in The Dayton Power and Light Company Retirement Income Plan or the participant’s death or disability. If a participant’s employment is terminated, other than by death or disability, prior to such participant becoming 100% vested in his or her account, the account shall be forfeited as of the date of termination. Vested benefits in the cash balance plan are fully portable upon termination of employment.
In addition, we have a Supplemental Executive Retirement Plan (SERP) for certain active and retired key executives. Benefits under this SERP have been frozen and no additional benefits can be earned. The SERP was replaced by the DPL Inc. Supplemental Executive Defined Contribution Retirement Plan (SEDCRP) effective January 1, 2006. The Compensation Committee of the Board of Directors designates the eligible employees. Pursuant to the SEDCRP, we provide a supplemental retirement benefit to participants by crediting an account established for each participant in accordance with the Plan requirements. We designate as hypothetical investment funds under the SEDCRP one or more of the investment funds provided under The
Dayton Power and Light Company Employee Savings Plan. Each participant may change his or her hypothetical investment fund selection at specified times. If a participant does not elect a hypothetical investment fund(s), then we select the hypothetical investment fund(s) for such participant. We also have an unfunded liability related to agreements for retirement benefits of certain terminated and retired key executives. The unfunded liabilities for these agreements and the SEDCRP were $0.8 million and $1.8 million at December 31, 2011 and 2010, respectively. Per the SEDCRP plan document, the balances in the SEDCRP, including earnings on contributions, were paid out to participants in December 2011. The SEDCRP continued and a contribution for 2011 was calculated in January 2012.
We generally fund pension plan benefits as accrued in accordance with the minimum funding requirements of the Employee Retirement Income Security Act of 1974 (ERISA) and, in addition, make voluntary contributions from time to time. DP&L made discretionary contributions of $40.0 million and $40.0 million to the defined benefit plan during the period January 1, 2011 through November 27, 2011 and the year ended December 31, 2010, respectively.
Qualified employees who retired prior to 1987 and their dependents are eligible for health care and life insurance benefits until their death, while qualified employees who retired after 1987 are eligible for life insurance benefits and partially subsidized health care. The partially subsidized health care is at the election of the employee, who pays the majority of the cost, and is available only from their retirement until they are covered by Medicare at age 65. We have funded a portion of the union-eligible benefits using a Voluntary Employee Beneficiary Association Trust.
Regulatory assets and liabilities are recorded for the portion of the under- or over-funded obligations related to the transmission and distribution areas of our electric business and for the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. These regulatory assets and liabilities represent the regulated portion that would otherwise be charged or credited to AOCI. We have historically recorded these costs on the accrual basis and this is how these costs have been historically recovered through customer rates. This factor, combined with the historical precedents from the PUCO and FERC, make these costs probable of future rate recovery.
The following tables set forth our pension and postretirement benefit plans’ obligations and assets recorded on the balance sheets as of December 31, 2011 and 2010. The amounts presented in the following tables for pension include the collective bargaining plan formula, traditional management plan formula and cash balance plan formula and the SERP in the aggregate. The amounts presented for postretirement include both health and life insurance benefits.
$ in millions | Pension | ||||||||||||
Successor | Predecessor | ||||||||||||
Change in Benefit Obligation | November 28, 2011 through December 31, 2011 | January 1, 2011 through November 27, 2011 | Year ended December 31, 2010 | ||||||||||
Benefit obligation at beginning of period | $ | 365.0 | $ | 333.8 | $ | 323.9 | |||||||
Service cost | 0.5 | 4.5 | 4.8 | ||||||||||
Interest cost | 1.5 | 15.5 | 17.7 | ||||||||||
Plan amendments | - | 7.2 | - | ||||||||||
Actuarial (gain) / loss | - | 21.6 | 8.0 | ||||||||||
Benefits paid | (1.8 | ) | (17.6 | ) | (20.6 | ) | |||||||
Benefit obligation at end of period | 365.2 | 365.0 | 333.8 | ||||||||||
Change in Plan Assets | |||||||||||||
Fair value of plan assets at beginning of period | 335.8 | 291.8 | 243.4 | ||||||||||
Actual return / (loss) on plan assets | 1.9 | 21.2 | 28.6 | ||||||||||
Contributions to plan assets | - | 40.4 | 40.4 | ||||||||||
Benefits paid | (1.8 | ) | (17.6 | ) | (20.6 | ) | |||||||
Fair value of plan assets at end of period | 335.9 | 335.8 | 291.8 | ||||||||||
Funded status of plan | $ | (29.3 | ) | $ | (29.2 | ) | $ | (42.0 | ) | ||||
$ in millions | Postretirement | ||||||||||||
Successor | Predecessor | ||||||||||||
Change in Benefit Obligation | November 28, 2011 through December 31, 2011 | January 1, 2011 through November 27, 2011 | Year ended December 31, 2010 | ||||||||||
Benefit obligation at beginning of period | $ | 21.9 | $ | 23.7 | $ | 26.2 | |||||||
Service cost | - | 0.1 | 0.1 | ||||||||||
Interest cost | 0.1 | 0.9 | 1.2 | ||||||||||
Plan amendments | - | - | - | ||||||||||
Actuarial (gain) / loss | (0.1 | ) | (1.3 | ) | (2.0 | ) | |||||||
Benefits paid | (0.2 | ) | (1.8 | ) | (2.0 | ) | |||||||
Medicare Part D Reimbursement | - | 0.3 | 0.2 | ||||||||||
Benefit obligation at end of period | 21.7 | 21.9 | 23.7 | ||||||||||
Change in Plan Assets | |||||||||||||
Fair value of plan assets at beginning of period | 4.5 | 4.8 | 5.0 | ||||||||||
Actual return / (loss) on plan assets | - | 0.2 | 0.3 | ||||||||||
Contributions to plan assets | 0.2 | 1.3 | 1.5 | ||||||||||
Benefits paid | (0.2 | ) | (1.8 | ) | (2.0 | ) | |||||||
Fair value of plan assets at end of period | 4.5 | 4.5 | 4.8 | ||||||||||
Funded status of plan | $ | (17.2 | ) | $ | (17.4 | ) | $ | (18.9 | ) |
$ in millions | Pension | Postretirement | ||||||||||||||||
Successor | Predecessor | Successor | Predecessor | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||||
Amounts Recognized in the | ||||||||||||||||||
Balance Sheets at December 31 | ||||||||||||||||||
Current liabilities | $ | (1.3 | ) | $ | (0.4 | ) | $ | (0.6 | ) | $ | (0.6 | ) | ||||||
Noncurrent liabilities | (27.9 | ) | (41.6 | ) | (16.6 | ) | (18.3 | ) | ||||||||||
Net asset / (liability) at December 31 | $ | (29.2 | ) | $ | (42.0 | ) | $ | (17.2 | ) | $ | (18.9 | ) | ||||||
Amounts Recognized in Accumulated Other | ||||||||||||||||||
Comprehensive Income, Regulatory Assets and | ||||||||||||||||||
Regulatory Liabilities, pre-tax | ||||||||||||||||||
Components: | ||||||||||||||||||
Prior service cost / (credit) | $ | 12.5 | $ | 16.8 | $ | 0.7 | $ | 0.9 | ||||||||||
Net actuarial loss / (gain) | 78.7 | 125.4 | (6.4 | ) | (7.6 | ) | ||||||||||||
Accumulated other comprehensive income, regulatory | ||||||||||||||||||
assets and regulatory liabilities, pre-tax | $ | 91.2 | $ | 142.2 | $ | (5.7 | ) | $ | (6.7 | ) | ||||||||
Recorded as: | ||||||||||||||||||
Regulatory asset | $ | 91.2 | $ | 80.0 | $ | 0.5 | $ | 0.5 | ||||||||||
Regulatory liability | - | - | (6.2 | ) | (6.1 | ) | ||||||||||||
Accumulated other comprehensive income | - | 62.2 | - | (1.1 | ) | |||||||||||||
Accumulated other comprehensive income, regulatory | ||||||||||||||||||
assets and regulatory liabilities, pre-tax | $ | 91.2 | $ | 142.2 | $ | (5.7 | ) | $ | (6.7 | ) |
The accumulated benefit obligation for our defined benefit pension plans was $355.5 million and $325.1 million at December 31, 2011 and 2010, respectively.
The net periodic benefit cost (income) of the pension and postretirement benefit plans were:
Successor | Predecessor | ||||||||||||||||
November 28, 2011 | January 1, 2011 | ||||||||||||||||
through | through | Years ended December 31, | |||||||||||||||
$ in millions | December 31, 2011 | November 27, 2011 | 2010 | 2009 | |||||||||||||
Service cost | $ | 0.5 | $ | 4.5 | $ | 4.8 | $ | 3.6 | |||||||||
Interest cost | 1.5 | 15.5 | 17.7 | 18.1 | |||||||||||||
Expected return on assets (a) | (2.0 | ) | (22.5 | ) | (22.4 | ) | (22.5 | ) | |||||||||
Amortization of unrecognized: | |||||||||||||||||
Actuarial (gain) / loss | 0.4 | 7.6 | 7.2 | 4.4 | |||||||||||||
Prior service cost | 0.1 | 2.0 | 3.7 | 3.4 | |||||||||||||
Net periodic benefit cost before adjustments | $ | 0.5 | $ | 7.1 | $ | 11.0 | $ | 7.0 |
(a) For purposes of calculating the expected return on pension plan assets, under GAAP, the market-related value of assets (MRVA) is used. GAAP requires that the difference between actual plan asset returns and estimated plan asset returns be amortized into the MRVA equally over a period not to exceed five years. We use a methodology under which we include the difference between actual and estimated asset returns in the MRVA equally over a three year period. The MRVA used in the calculation of expected return on pension plan assets was approximately $317 million in 2011, $274 million in 2010, and $275 million in 2009.
Net Periodic Benefit Cost / (Income) - Postretirement | |||||||||||||||||
Successor | Predecessor | ||||||||||||||||
November 28, 2011 | January 1, 2011 | ||||||||||||||||
through | through | Years ended December 31, | |||||||||||||||
$ in millions | December 31, 2011 | November 27, 2011 | 2010 | 2009 | |||||||||||||
Service cost | $ | - | $ | 0.1 | $ | 0.1 | $ | - | |||||||||
Interest cost | 0.1 | 0.9 | 1.2 | 1.5 | |||||||||||||
Expected return on assets (a) | - | (0.3 | ) | (0.3 | ) | (0.4 | ) | ||||||||||
Amortization of unrecognized: | |||||||||||||||||
Actuarial (gain) / loss | - | (1.0 | ) | (1.1 | ) | (0.7 | ) | ||||||||||
Prior service cost | (0.1 | ) | 0.1 | 0.1 | 0.1 | ||||||||||||
Net periodic benefit cost / (income) before adjustments | $ | - | $ | (0.2 | ) | $ | - | $ | 0.5 |
Other Changes in Plan Assets and Benefit Obligation Recognized in Accumulated Other
Comprehensive Income, Regulatory Assets and Regulatory Liabilities
Pension | Successor | Predecessor | |||||||||||||||
November 28, 2011 | January 1, 2011 | ||||||||||||||||
through | through | Years ended December 31, | |||||||||||||||
$ in millions | December 31, 2011 | November 27, 2011 | 2010 | 2009 | |||||||||||||
Net actuarial (gain) / loss | $ | - | $ | (38.7 | ) | $ | 1.9 | $ | 5.3 | ||||||||
Prior service cost / (credit) | - | (2.2 | ) | - | 7.2 | ||||||||||||
Reversal of amortization item: | |||||||||||||||||
Net actuarial (gain) / loss | (0.4 | ) | (7.6 | ) | (7.2 | ) | (4.4 | ) | |||||||||
Prior service cost / (credit) | (0.1 | ) | (2.0 | ) | (3.7 | ) | (3.4 | ) | |||||||||
Transition (asset) / obligation | - | - | - | - | |||||||||||||
Total recognized in Accumulated other comprehensive income, | |||||||||||||||||
Regulatory assets and Regulatory liabilities | $ | (0.5 | ) | $ | (50.5 | ) | $ | (9.0 | ) | $ | 4.7 | ||||||
Total recognized in net periodic benefit cost and Accumulated | |||||||||||||||||
other comprehensive income, Regulatory assets and | |||||||||||||||||
Regulatory liabilities | $ | (0.5 | ) | $ | (43.4 | ) | $ | 2.0 | $ | 11.7 | |||||||
Postretirement | Successor | Predecessor | |||||||||||||||
November 28, 2011 | January 1, 2011 | ||||||||||||||||
through | through | Years ended December 31, | |||||||||||||||
$ in millions | December 31, 2011 | November 27, 2011 | 2010 | 2009 | |||||||||||||
Net actuarial (gain) / loss | $ | - | $ | 0.2 | $ | (1.9 | ) | $ | 0.3 | ||||||||
Prior service cost / (credit) | (0.1 | ) | (0.1 | ) | - | 1.1 | |||||||||||
Reversal of amortization item: | |||||||||||||||||
Net actuarial (gain) / loss | - | 1.0 | 1.1 | 0.7 | |||||||||||||
Prior service cost / (credit) | 0.1 | (0.1 | ) | (0.1 | ) | (0.1 | ) | ||||||||||
Transition (asset) / obligation | - | - | - | - | |||||||||||||
Total recognized in Accumulated other comprehensive income, | |||||||||||||||||
Regulatory assets and Regulatory liabilities | $ | - | $ | 1.0 | $ | (0.9 | ) | $ | 2.0 | ||||||||
Total recognized in net periodic benefit cost and Accumulated | |||||||||||||||||
other comprehensive income, Regulatory assets and | |||||||||||||||||
Regulatory liabilities | $ | - | $ | 0.8 | $ | (0.9 | ) | $ | 2.5 |
Estimated amounts that will be amortized from Accumulated other comprehensive income, Regulatory assets and Regulatory liabilities into net periodic benefit costs during 2012 are:
$ in millions | Pension | Postretirement | ||||||
Net actuarial (gain) / loss | $ | 4.9 | $ | 0.1 | ||||
Prior service cost / (credit) | 1.6 | (0.8 | ) |
Our expected return on plan asset assumptions, used to determine benefit obligations, are based on historical long-term rates of return on investments, which use the widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current market factors, such as inflation and interest rates, as well as asset diversification and portfolio rebalancing, are evaluated when long-term capital market assumptions are determined. Peer data and historical returns are reviewed to verify reasonableness and appropriateness.
For the Successor period in 2011 and continuing in 2012, we have decreased our expected long-term rate of return on assets assumption from 8.00% to 7.00% for pension plan assets. We are maintaining our expected long-term rate of return on assets assumption at approximately 6.00% for postretirement benefit plan assets. These expected returns are based primarily on portfolio investment allocation. There can be no assurance of our ability to generate these rates of return in the future.
Our overall discount rate was evaluated in relation to the Hewitt Top Quartile Yield Curve which represents a portfolio of top-quartile AA-rated bonds used to settle pension obligations. Peer data and historical returns were also reviewed to verify the reasonableness and appropriateness of our discount rate used in the calculation of benefit obligations and expense.
The weighted average assumptions used to determine benefit obligations during 2011, 2010 and 2009 were:
Benefit Obligation Assumptions | Pension | Postretirement | ||||||||||||||||||||||
2011 | 2010 | 2009 | 2011 | 2010 | 2009 | |||||||||||||||||||
Discount rate for obligations | 4.88 | % | 5.31 | % | 5.75 | % | 4.17 | % | 4.96 | % | 5.35 | % | ||||||||||||
Rate of compensation increases | 3.94 | % | 3.94 | % | 4.44 | % | N/A | N/A | N/A |
The weighted-average assumptions used to determine net periodic benefit cost (income) for the years ended December 31, 2011, 2010 and 2009 were:
Net Periodic Benefit | ||||||||||||||||||||||||
Cost / (Income) Assumptions | Pension | Postretirement | ||||||||||||||||||||||
2011 | 2010 | 2009 | 2011 | 2010 | 2009 | |||||||||||||||||||
Discount rate (Predecessor/Successor) | 5.31% / 4.88 | % | 5.75 | % | 6.25 | % | 4.96% / 4.62 | % | 5.35 | % | 6.25 | % | ||||||||||||
Expected rate of return on plan assets | ||||||||||||||||||||||||
(Predecessor/Successor) | 8.00% / 7.00 | % | 8.50 | % | 8.50 | % | 6.00% / 6.00 | % | 6.00 | % | 6.00 | % | ||||||||||||
Rate of compensation increases | ||||||||||||||||||||||||
(Predecessor/Successor) | 3.94% / 3.94 | % | 4.44 | % | 5.44 | % | N/A | N/A | N/A |
The assumed health care cost trend rates at December 31, 2011, 2010 and 2009 are as follows:
Health Care Cost Assumptions | Expense | Benefit Obligations | ||||||||||||||||||||||
2011 | 2010 | 2009 | 2011 | 2010 | 2009 | |||||||||||||||||||
Pre - age 65 | ||||||||||||||||||||||||
Current health care cost trend rate | 8.50 | % | 9.50 | % | 9.50 | % | 8.50 | % | 8.50 | % | 9.50 | % | ||||||||||||
Year trend reaches ultimate | ||||||||||||||||||||||||
(Predecessor/Successor) | 2018/2019 | 2015 | 2014 | 2019 | 2018 | 2015 | ||||||||||||||||||
Post - age 65 | ||||||||||||||||||||||||
Current health care cost trend rate | 8.00 | % | 9.00 | % | 9.00 | % | 8.00 | % | 8.00 | % | 9.00 | % | ||||||||||||
Year trend reaches ultimate | ||||||||||||||||||||||||
(Predecessor/Successor) | 2017/2018 | 2014 | 2013 | 2018 | 2017 | 2014 | ||||||||||||||||||
Ultimate health care cost trend rate | 5.00 | % | 5.00 | % | 5.00 | % | 5.00 | % | 5.00 | % | 5.00 | % |
The assumed health care cost trend rates have an effect on the amounts reported for the health care plans. A one-percentage point change in assumed health care cost trend rates would have the following effects on the net periodic postretirement benefit cost and the accumulated postretirement benefit obligation:
Effect of Change in Health Care Cost Trend Rate | One-percent | One-percent | ||||||
$ in millions | increase | decrease | ||||||
Service cost plus interest cost | $ | - | $ | - | ||||
Benefit obligation | $ | 0.9 | $ | (0.8 | ) |
Benefit payments, which reflect future service, are expected to be paid as follows:
Estimated Future Benefit Payments and Medicare Part D Reimbursements | ||||||||
$ in millions | Pension | Postretirement | ||||||
2012 | $ | 23.1 | $ | 2.6 | ||||
2013 | $ | 22.7 | $ | 2.5 | ||||
2014 | $ | 23.2 | $ | 2.4 | ||||
2015 | $ | 23.8 | $ | 2.2 | ||||
2016 | $ | 24.0 | $ | 2.1 | ||||
2017 - 2021 | $ | 124.4 | $ | 8.2 |
We expect to make contributions of $1.4 million to our SERP in 2012 to cover benefit payments. We also expect to contribute $2.3 million to our other postretirement benefit plans in 2012 to cover benefit payments.
The Pension Protection Act (the Act) of 2006 contained new requirements for our single employer defined benefit pension plan. In addition to establishing a 100% funding target for plan years beginning after December 31, 2008, the Act also limits some benefits if the funded status of pension plans drops below certain thresholds. Among other restrictions under the Act, if the funded status of a plan falls below a predetermined ratio of 80%, lump-sum payments to new retirees are limited to 50% of amounts that otherwise would have been paid and new benefit improvements may not go into effect. For the 2011 plan year, the funded status of our defined benefit pension plan as calculated under the requirements of the Act was 104.37% and is estimated to be 104.37% until the 2012 status is certified in September 2012 for the 2012 plan year. The Worker, Retiree, and Employer Recovery Act of 2008 (WRERA), which was signed into law on December 23, 2008, grants plan sponsors certain relief from funding requirements and benefit restrictions of the Act.
Plan Assets
Plan assets are invested using a total return investment approach whereby a mix of equity securities, debt securities and other investments are used to preserve asset values, diversify risk and achieve our target investment return benchmark. Investment strategies and asset allocations are based on careful consideration of plan liabilities, the plan's funded status and our financial condition. Investment performance and asset allocation are measured and monitored on an ongoing basis.
Plan assets are managed in a balanced portfolio comprised of two major components: an equity portion and a fixed income portion. The expected role of Plan equity investments is to maximize the long-term real growth of Plan assets, while the role of fixed income investments is to generate current income, provide for more stable periodic returns and provide some protection against a prolonged decline in the market value of Plan equity investments.
Long-term strategic asset allocation guidelines are determined by management and take into account the Plan’s long-term objectives as well as its short-term constraints. The target allocations for plan assets are 30-80% for equity securities, 30-65% for fixed income securities, 0-10% for cash and 0-25% for alternative investments. Equity securities include U.S. and international equity, while fixed income securities include long-duration and high-yield bond funds and emerging market debt funds. Other types of investments include investments in hedge funds and private equity funds that follow several different strategies.
The fair values of our pension plan assets at December 31, 2011 by asset category are as follows:
Fair Value Measurements for Pension Plan Assets at December 31, 2011 (Successor) | ||||||||||||||||
Asset Category $ in millions | Market Value at December 31, 2011 | Quoted Prices in Active Markets for Identical Assets | Significant Observable Inputs | Significant Unobservable Inputs | ||||||||||||
(Level 1) | (Level 2) | (Level 3) | ||||||||||||||
Equity Securities (a) | ||||||||||||||||
Small/Mid Cap Equity | $ | 16.2 | $ | - | $ | 16.2 | $ | - | ||||||||
Large Cap Equity | 54.5 | - | 54.5 | - | ||||||||||||
International Equity | 34.2 | - | 34.2 | - | ||||||||||||
Total Equity Securities | 104.9 | - | 104.9 | - | ||||||||||||
Debt Securities (b) | ||||||||||||||||
Emerging Markets Debt | - | - | - | - | ||||||||||||
Fixed Income | - | - | - | - | ||||||||||||
High Yield Bond | - | - | - | - | ||||||||||||
Long Duration Fund | 130.8 | - | 130.8 | - | ||||||||||||
Total Debt Securities | 130.8 | - | 130.8 | - | ||||||||||||
Cash and Cash Equivalents (c) | ||||||||||||||||
Cash | 28.0 | 28.0 | - | - | ||||||||||||
Other Investments (d) | ||||||||||||||||
Limited Partnership Interest | 0.8 | - | - | 0.8 | ||||||||||||
Common Collective Fund | 71.4 | - | - | 71.4 | ||||||||||||
Total Other Investments | 72.2 | - | - | 72.2 | ||||||||||||
Total Pension Plan Assets | $ | 335.9 | $ | 28.0 | $ | 235.7 | $ | 72.2 |
(a) | This category includes investments in equity securities of large, small and medium sized companies and equity securities of foreign companies including those in developing countries. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund. |
(b) | This category includes investments in investment-grade fixed-income instruments that are designed to mirror the term of the pension assets and generally have a tenor between 10 and 30 years. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund. |
(c) | This category comprises cash held to pay beneficiaries and the proceeds received from the DPL Inc. Common Stock, which was cashed-out at $30/share. The fair value of cash equals its book value. (Subsequent to the measurement date, the proceeds from the DPL Inc. Common Stock were invested in the other various investments.) |
(d) | This category represents a private equity fund that specializes in management buyouts and a hedge fund of funds made up of 30+ different hedge fund managers diversified over eight different hedge strategies. The fair value of the private equity fund is determined by the General Partner based on the performance of the individual companies. The fair value of the hedge fund is valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund. |
The fair values of our pension plan assets at December 31, 2010 by asset category are as follows:
Fair Value Measurements for Pension Plan Assets at December 31, 2010 (Predecessor) | ||||||||||||||||
Asset Category $ in millions | Market Value at December 31, 2010 | Quoted Prices in Active Markets for Identical Assets | Significant Observable Inputs | Significant Unobservable Inputs | ||||||||||||
(Level 1) | (Level 2) | (Level 3) | ||||||||||||||
Equity Securities (a) | ||||||||||||||||
Small/Mid Cap Equity | $ | 15.2 | $ | - | $ | 15.2 | $ | - | ||||||||
Large Cap Equity | 49.4 | - | 49.4 | - | ||||||||||||
DPL Inc. Common Stock | 23.8 | 23.8 | - | - | ||||||||||||
International Equity | 31.5 | - | 31.5 | - | ||||||||||||
Total Equity Securities | 119.9 | 23.8 | 96.1 | - | ||||||||||||
Debt Securities (b) | ||||||||||||||||
Emerging Markets Debt | 5.2 | - | 5.2 | - | ||||||||||||
Fixed Income | 39.0 | - | 39.0 | |||||||||||||
High Yield Bond | 8.2 | - | 8.2 | - | ||||||||||||
Long Duration Fund | 58.9 | - | 58.9 | - | ||||||||||||
Total Debt Securities | 111.3 | - | 111.3 | - | ||||||||||||
Cash and Cash Equivalents (c) | ||||||||||||||||
Cash | 0.4 | 0.4 | - | - | ||||||||||||
Other Investments (d) | ||||||||||||||||
Limited Partnership Interest | 2.8 | - | - | 2.8 | ||||||||||||
Common Collective Fund | 57.4 | - | - | 57.4 | ||||||||||||
Total Other Investments | 60.2 | - | - | 60.2 | ||||||||||||
Total Pension Plan Assets | $ | 291.8 | $ | 24.2 | $ | 207.4 | $ | 60.2 |
(a) | This category includes investments in equity securities of large, small and medium sized companies and equity securities of foreign companies including those in developing countries. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund except for the DPL common stock which is valued using the closing price on the New York Stock Exchange. |
(b) | This category includes investments in investment-grade fixed-income instruments, U.S. dollar-denominated debt securities of emerging market issuers and high yield fixed-income securities that are rated below investment grade. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund. |
(c) | This category comprises cash held to pay beneficiaries. The fair value of cash equals its book value. |
(d) | This category represents a private equity fund that specializes in management buyouts and a hedge fund of funds made up of 30+ different hedge fund managers diversified over eight different hedge strategies. The fair value of the private equity fund is determined by the General Partner based on the performance of the individual companies. The fair value of the hedge fund is valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund. |
The change in the fair value for the pension assets valued using significant unobservable inputs (Level 3) was due to the following:
Fair Value Measurements of Pension Assets Using Significant Unobservable Inputs | ||||||||
(Level 3) | ||||||||
$ in millions | Limited Partnership Interest | Common Collective Fund | ||||||
2010 (Predecessor): | ||||||||
Beginning balance January 1, 2010 | $ | 3.1 | $ | 50.6 | ||||
Actual return on plan assets: | ||||||||
Relating to assets still held at the reporting date | 0.1 | 0.8 | ||||||
Relating to assets sold during the period | - | - | ||||||
Purchases, sales, and settlements | (0.4 | ) | 6.0 | |||||
Transfers in and / or out of Level 3 | - | - | ||||||
Ending balance at December 31, 2010 | $ | 2.8 | $ | 57.4 | ||||
January 1, 2011 through November 27, 2011 (Predecessor): | ||||||||
Beginning balance January 1, 2011 | $ | 2.8 | $ | 57.4 | ||||
Actual return on plan assets: | ||||||||
Relating to assets still held at the reporting date | (0.8 | ) | (1.5 | ) | ||||
Relating to assets sold during the period | - | - | ||||||
Purchases, sales, and settlements | (1.1 | ) | 15.4 | |||||
Transfers in and / or out of Level 3 | - | - | ||||||
Ending balance at November 27, 2011 | $ | 0.9 | $ | 71.3 | ||||
November 28, 2011 through December 31, 2011 (Successor): | ||||||||
Beginning balance November 28, 2011 | $ | 0.9 | $ | 71.3 | ||||
Actual return on plan assets: | ||||||||
Relating to assets still held at the reporting date | - | 0.1 | ||||||
Relating to assets sold during the period | - | - | ||||||
Purchases, sales, and settlements | (0.1 | ) | - | |||||
Transfers in and / or out of Level 3 | - | - | ||||||
Ending balance at December 31, 2011 | $ | 0.8 | $ | 71.4 |
The fair values of our other postretirement benefit plan assets at December 31, 2011 by asset category are as follows:
Fair Value Measurements for Postretirement Plan Assets at December 31, 2011 (Successor) | ||||||||||||||||
Asset Category $ in millions | Market Value at 12/31/11 | Quoted Prices in Active Markets for Identical Assets | Significant Observable Inputs | Significant Unobservable Inputs | ||||||||||||
(Level 1) | (Level 2) | (Level 3) | ||||||||||||||
JP Morgan Core Bond Fund (a) | $ | 4.5 | $ | - | $ | 4.5 | $ | - |
(a) | This category includes investments in U.S. government obligations and mortgage-backed and asset-backed securities. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund. |
The fair values of our other postretirement benefit plan assets at December 31, 2010 by asset category are as follows:
Fair Value Measurements for Postretirement Plan Assets at December 31, 2010 (Predecessor) | ||||||||||||||||
Asset Category $ in millions | Market Value at 12/31/10 | Quoted Prices in Active Markets for Identical Assets | Significant Observable Inputs | Significant Unobservable Inputs | ||||||||||||
(Level 1) | (Level 2) | (Level 3) | ||||||||||||||
JP Morgan Core Bond Fund (a) | $ | 4.8 | $ | - | $ | 4.8 | $ | - |
(a) | This category includes investments in U.S. government obligations and mortgage-backed and asset-backed securities. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund. |
10. Fair Value Measurements |
The fair values of our financial instruments are based on published sources for pricing when possible. We rely on valuation models only when no other method is available to us. The fair value of our financial instruments represents estimates of possible value that may or may not be realized in the future. The table below presents the fair value and cost of our non-derivative instruments at December 31, 2011 and 2010. See also Note 11 for the fair values of our derivative instruments.
Successor | Predecessor | ||||||||||||||||
At December 31, | At December 31, | ||||||||||||||||
2011 | 2010 | ||||||||||||||||
$ in millions | Cost | Fair Value | Cost | Fair Value | |||||||||||||
DPL | |||||||||||||||||
Assets | |||||||||||||||||
Money Market Funds | $ | 0.2 | $ | 0.2 | $ | 1.6 | $ | 1.6 | |||||||||
Equity Securities | 3.9 | 4.4 | 3.8 | 4.4 | |||||||||||||
Debt Securities | 5.0 | 5.5 | 5.2 | 5.5 | |||||||||||||
Multi-Strategy Fund | 0.3 | 0.2 | 0.3 | 0.3 | |||||||||||||
9.4 | 10.3 | 10.9 | 11.8 | ||||||||||||||
Short-term Investments - VRDNs | - | - | 54.2 | 54.2 | |||||||||||||
Short-term Investments - Bonds | - | - | 15.1 | 15.1 | |||||||||||||
Total Short-term Investments | - | - | 69.3 | 69.3 | |||||||||||||
Total Assets | $ | 9.4 | $ | 10.3 | $ | 80.2 | $ | 81.1 | |||||||||
Liabilities | |||||||||||||||||
Debt | $ | 2,629.3 | $ | 2,710.6 | $ | 1,324.1 | $ | 1,307.5 |
Debt
The carrying value of DPL’s debt was adjusted to fair value at the Merger date. The fair value of the debt at December 31, 2011 did not change substantially from the value at the Merger date. Unrealized gains or losses are not recognized in the financial statements as debt is presented at the carrying value established at the Merger date, net of unamortized premium or discount in the financial statements. The debt amounts include the current portion payable in the next twelve months and have maturities that range from 2013 to 2061.
Master Trust Assets
DP&L established a Master Trust to hold assets that could be used for the benefit of employees participating in employee benefit plans. These assets are primarily comprised of open-ended mutual funds which are valued using the net asset value per unit. These investments are recorded at fair value within Other deferred assets on
the balance sheets and classified as available for sale. Any unrealized gains or losses are recorded in AOCI until the securities are sold.
DPL had immaterial unrealized gains and losses on the Master Trust assets in AOCI at December 31, 2011 and $0.9 million ($0.6 million after tax) in unrealized gains and immaterial unrealized losses in AOCI at December 31, 2010.
Due to the liquidation of the DPL Inc. common stock held in the Master Trust, there is sufficient cash to cover the next twelve months of benefits payable to employees covered under the benefit plans covered by the trust. Therefore, no unrealized gains or losses are expected to be transferred to earnings since we will not need to sell any investments in the next twelve months.
Short-term Investments
DPL, from time to time, utilizes VRDNs as part of its short-term investment strategy. The VRDNs are of high credit quality and are secured by irrevocable letters of credit from major financial institutions. VRDN investments have variable rates tied to short-term interest rates. Interest rates are reset every seven days and these VRDNs can be tendered for sale upon notice back to the financial institution. Although DPL’s VRDN investments have original maturities over one year, they are frequently re-priced and trade at par. We account for these VRDNs as available-for-sale securities and record them as short-term investments at fair value, which approximates cost, since they are highly liquid and are readily available to support DPL’s current operating needs.
DPL also from time to time utilizes investment-grade fixed income corporate securities in its short-term investment portfolio. These securities are accounted for as held-to-maturity investments.
Net Asset Value (NAV) per Unit
The following table discloses the fair value and redemption frequency for those assets whose fair value is estimated using the NAV per unit as of December 31, 2011 and 2010. These assets are part of the Master Trust. Fair values estimated using the NAV per unit are considered Level 2 inputs within the fair value hierarchy, unless they cannot be redeemed at the NAV per unit on the reporting date. Investments that have restrictions on the redemption of the investments are Level 3 inputs. As of December 31, 2011, DPL did not have any investments for sale at a price different from the NAV per unit.
Fair Value Estimated Using Net Asset Value per Unit (Successor) | |||||||||
$ in millions | Fair Value at December 31, 2011 | Unfunded Commitments | Redemption Frequency | ||||||
Money Market Fund (a) | $ | 0.2 | $ | - | Immediate | ||||
Equity Securities (b) | 4.4 | - | Immediate | ||||||
Debt Securities (c) | 5.5 | - | Immediate | ||||||
Multi-Strategy Fund (d) | 0.2 | - | Immediate | ||||||
Total | $ | 10.3 | $ | - |
Fair Value Estimated Using Net Asset Value per Unit (Predecessor) | |||||||||
$ in millions | Fair Value at December 31, 2010 | Unfunded Commitments | Redemption Frequency | ||||||
Money Market Fund (a) | $ | 1.6 | $ | - | Immediate | ||||
Equity Securities (b) | 4.4 | - | Immediate | ||||||
Debt Securities (c) | 5.5 | - | Immediate | ||||||
Multi-Strategy Fund (d) | 0.3 | - | Immediate | ||||||
Total | $ | 11.8 | $ | - |
(a) This category includes investments in high-quality, short-term securities. Investments in this category can be redeemed immediately at the current net asset value per unit. |
(b) This category includes investments in hedge funds representing an S&P 500 index and the Morgan Stanley Capital International (MSCI) U.S. Small Cap 1750 Index. Investments in this category can be redeemed immediately at the current net asset value per unit. |
(c) This category includes investments in U.S. Treasury obligations and U.S. investment grade bonds. Investments in this category can be redeemed immediately at the current net asset value per unit. |
(d) This category includes a mix of actively managed funds holding investments in stocks, bonds and short-term investments in a mix of actively managed funds. Investments in this category can be redeemed immediately at the current net asset value per unit. |
Fair Value Hierarchy
Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. These inputs are then categorized as Level 1 (quoted prices in active markets for identical assets or liabilities); Level 2 (observable inputs such as quoted prices for similar assets or liabilities or quoted prices in markets that are not active); or Level 3 (unobservable inputs).
Valuations of assets and liabilities reflect the value of the instrument including the values associated with counterparty risk. We include our own credit risk and our counterparty’s credit risk in our calculation of fair value using global average default rates based on an annual study conducted by a large rating agency.
We did not have any transfers of the fair values of our financial instruments between Level 1 and Level 2 of the fair value hierarchy during the twelve months ended December 31, 2011 and 2010.
The fair value of assets and liabilities at December 31, 2011 measured on a recurring basis and the respective category within the fair value hierarchy for DPL was determined as follows:
Successor | ||||||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | ||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | ||||||||||||||||||||||
$ in millions | Fair Value at December 31, 2011* | Based on Quoted Prices in Active Markets | Other Observable Inputs | Unobservable Inputs | Collateral and Counterparty Netting | Fair Value on Balance Sheet at December 31, 2011 | ||||||||||||||||||
Assets | ||||||||||||||||||||||||
Master Trust Assets | ||||||||||||||||||||||||
Money Market Funds | $ | 0.2 | $ | - | $ | 0.2 | $ | - | $ | - | $ | 0.2 | ||||||||||||
Equity Securities | 4.4 | - | 4.4 | - | - | 4.4 | ||||||||||||||||||
Debt Securities | 5.5 | - | 5.5 | - | - | 5.5 | ||||||||||||||||||
Multi-Strategy Fund | 0.2 | - | 0.2 | - | - | 0.2 | ||||||||||||||||||
Total Master Trust Assets | 10.3 | - | 10.3 | - | - | 10.3 | ||||||||||||||||||
Derivative Assets | ||||||||||||||||||||||||
FTRs | 0.1 | - | 0.1 | - | - | 0.1 | ||||||||||||||||||
Heating Oil Futures | 1.8 | 1.8 | - | - | (1.8 | ) | - | |||||||||||||||||
Forward Power Contracts | 17.3 | - | 17.3 | - | (1.0 | ) | 16.3 | |||||||||||||||||
Total Derivative Assets | 19.2 | 1.8 | 17.4 | - | (2.8 | ) | 16.4 | |||||||||||||||||
Short-term Investments - VRDNs | - | - | - | - | - | - | ||||||||||||||||||
Short-term Investments - Bonds | - | - | - | - | - | - | ||||||||||||||||||
Total Short-term investments | - | - | - | - | - | - | ||||||||||||||||||
Total Assets | $ | 29.5 | $ | 1.8 | $ | 27.7 | $ | - | $ | (2.8 | ) | $ | 26.7 | |||||||||||
Liabilities | ||||||||||||||||||||||||
Derivative Liabilities | ||||||||||||||||||||||||
Interest Rate Hedge | $ | (32.5 | ) | $ | - | $ | (32.5 | ) | $ | - | $ | - | $ | (32.5 | ) | |||||||||
Forward NYMEX Coal Contracts | (14.5 | ) | - | (14.5 | ) | - | 10.8 | (3.7 | ) | |||||||||||||||
Forward Power Contracts | (13.3 | ) | - | (13.3 | ) | - | 5.6 | (7.7 | ) | |||||||||||||||
Total Derivative Liabilities | (60.3 | ) | - | (60.3 | ) | - | 16.4 | (43.9 | ) | |||||||||||||||
Total Liabilities | $ | (60.3 | ) | $ | - | $ | (60.3 | ) | $ | - | $ | 16.4 | $ | (43.9 | ) |
*Includes credit valuation adjustments for counterparty risk.
The fair value of assets and liabilities at December 31, 2010 measured on a recurring basis and the respective category within the fair value hierarchy for DPL was determined as follows:
Predecessor | ||||||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | ||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | ||||||||||||||||||||||
$ in millions | Fair Value at December 31, 2010* | Based on Quoted Prices in Active Markets | Other Observable Inputs | Unobservable Inputs | Collateral and Counterparty Netting | Fair Value on Balance Sheet at December 31, 2010 | ||||||||||||||||||
Assets | ||||||||||||||||||||||||
Master Trust Assets | ||||||||||||||||||||||||
Money Market Funds | $ | 1.6 | $ | - | $ | 1.6 | $ | - | $ | - | $ | 1.6 | ||||||||||||
Equity Securities (a) | 4.4 | - | 4.4 | - | - | 4.4 | ||||||||||||||||||
Debt Securities | 5.5 | - | 5.5 | - | - | 5.5 | ||||||||||||||||||
Multi-Strategy Fund | 0.3 | - | 0.3 | - | - | 0.3 | ||||||||||||||||||
Total Master Trust Assets | 11.8 | - | 11.8 | - | - | 11.8 | ||||||||||||||||||
Derivative Assets | ||||||||||||||||||||||||
FTRs | 0.3 | - | 0.3 | - | - | 0.3 | ||||||||||||||||||
Heating Oil Futures | 1.6 | 1.6 | - | - | (1.6 | ) | - | |||||||||||||||||
Interest Rate Hedge | 20.7 | - | 20.7 | - | - | 20.7 | ||||||||||||||||||
Forward NYMEX Coal Contracts | 37.5 | - | 37.5 | - | (21.9 | ) | 15.6 | |||||||||||||||||
Forward Power Contracts | 0.2 | - | 0.2 | - | (0.2 | ) | - | |||||||||||||||||
Total Derivative Assets | 60.3 | 1.6 | 58.7 | - | (23.7 | ) | 36.6 | |||||||||||||||||
Short-term Investments - VRDNs | 54.2 | - | 54.2 | - | - | 54.2 | ||||||||||||||||||
Short-term Investments - Bonds | 15.1 | - | 15.1 | - | - | 15.1 | ||||||||||||||||||
Total Short-term investments | 69.3 | - | 69.3 | - | - | 69.3 | ||||||||||||||||||
Total Assets | $ | 141.4 | $ | 1.6 | $ | 139.8 | $ | - | $ | (23.7 | ) | $ | 117.7 | |||||||||||
Liabilities | ||||||||||||||||||||||||
Derivative Liabilities | ||||||||||||||||||||||||
Interest Rate Hedge | $ | 6.6 | $ | - | $ | 6.6 | $ | - | $ | - | $ | 6.6 | ||||||||||||
Forward Power Contracts | 3.1 | - | 3.1 | - | (1.1 | ) | 2.0 | |||||||||||||||||
Total Derivative Liabilities | 9.7 | - | 9.7 | - | (1.1 | ) | 8.6 | |||||||||||||||||
Total Liabilities | $ | 9.7 | $ | - | $ | 9.7 | $ | - | $ | (1.1 | ) | $ | 8.6 |
*Includes credit valuation adjustments for counterparty risk.
(a) DPL stock in the Master Trust was eliminated in consolidation.
We use the market approach to value our financial instruments. Level 1 inputs are used for derivative contracts such as heating oil futures. The fair value is determined by reference to quoted market prices and other relevant information generated by market transactions. Level 2 inputs are used to value derivatives such as financial transmission rights (where the quoted prices are from a relatively inactive market), forward power contracts and forward NYMEX-quality coal contracts (which are traded on the OTC market but which are valued using prices on the NYMEX for similar contracts on the OTC market). VRDNs and bonds are considered Level 2 because they are priced using recent transactions for similar assets. Other Level 2 assets include: open-ended mutual funds that are in the Master Trust, which are valued using the end of day NAV per unit; and interest rate hedges, which use observable inputs to populate a pricing model.
Approximately 97% of the inputs to the fair value of our derivative instruments are from quoted market prices.
Non-recurring Fair Value Measurements
We use the cost approach to determine the fair value of our AROs which are estimated by discounting expected cash outflows to their present value at the initial recording of the liability. Cash outflows are based on the approximate future disposal cost as determined by market information, historical information or other management estimates. These inputs to the fair value of the AROs would be considered Level 3 inputs under the fair value hierarchy. There were $1.0 million and $1.4 million of gross additions to our existing river structures and asbestos AROs during the twelve months ended December 31, 2011 and 2010. In addition, it was determined that a river structure would be retired earlier than previously estimated. This resulted in a partial reduction to the ARO liability of $0.8 million in 2010.
Cash Equivalents
DPL had $125.0 million and $29.9 million in money market funds classified as cash and cash equivalents in its Consolidated Balance Sheets at December 31, 2011 and 2010, respectively. The money market funds have quoted prices that are generally equivalent to par.
11. Derivative Instruments and Hedging Activities |
In the normal course of business, DPL enters into various financial instruments, including derivative financial instruments. We use derivatives principally to manage the risk of changes in market prices for commodities and interest rate risk associated with our long-term debt. The derivatives that we use to economically hedge these risks are governed by our risk management policies for forward and futures contracts. Our asset and liability derivative positions with the same counterparty are netted on the balance sheet if we have a Master Netting Agreement with the counterparty. We also net any collateral posted or received against the corresponding derivative asset or liability position. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The objective of the hedging program is to mitigate financial risks while ensuring that we have adequate resources to meet our requirements. We monitor and value derivative positions monthly as part of our risk management processes. We use published sources for pricing, when possible, to mark positions to market. All of our derivative instruments are used for risk management purposes and are designated as cash flow hedges or marked to market each reporting period.
At December 31, 2011, DPL had the following outstanding derivative instruments:
Successor | Purchases | Sales | Net Purchases/ (Sales) | |||||||||||
Commodity | Accounting Treatment | Unit | (in thousands) | (in thousands) | (in thousands) | |||||||||
FTRs | Mark to Market | MWh | 7.1 | (0.7 | ) | 6.4 | ||||||||
Heating Oil Futures | Mark to Market | Gallons | 2,772.0 | - | 2,772.0 | |||||||||
Forward Power Contracts | Cash Flow Hedge | MWh | 886.2 | (341.6 | ) | 544.6 | ||||||||
Forward Power Contracts | Mark to Market | MWh | 1,769.4 | (1,739.5 | ) | 29.9 | ||||||||
NYMEX-quality Coal Contracts* | Mark to Market | Tons | 2,015.0 | - | 2,015.0 | |||||||||
Interest Rate Swaps | Cash Flow Hedge | USD | 160,000.0 | - | 160,000.0 |
*Includes our partners' share for the jointly-owned plants that DP&L operates.
At December 31, 2010, DPL had the following outstanding derivative instruments:
Predecessor | Purchases | Sales | Net Purchases/ (Sales) | |||||||||||
Commodity | Accounting Treatment | Unit | (in thousands) | (in thousands) | (in thousands) | |||||||||
FTRs | Mark to Market | MWh | 9.0 | - | 9.0 | |||||||||
Heating Oil Futures | Mark to Market | Gallons | 6,216.0 | - | 6,216.0 | |||||||||
Forward Power Contracts | Cash Flow Hedge | MWh | 580.8 | (572.9 | ) | 7.9 | ||||||||
Forward Power Contracts | Mark to Market | MWh | 195.6 | (108.5 | ) | 87.1 | ||||||||
NYMEX-quality Coal Contracts* | Mark to Market | Tons | 4,006.8 | - | 4,006.8 | |||||||||
Interest Rate Swaps | Cash Flow Hedge | USD | 360,000.0 | - | 360,000.0 |
*Includes our partners' share for the jointly-owned plants that DP&L operates.
Cash Flow Hedges
As part of our risk management processes, we identify the relationships between hedging instruments and hedged items, as well as the risk management objective and strategy for undertaking various hedge transactions. The fair value of cash flow hedges as determined by current public market prices will continue to fluctuate with changes in market prices up to contract expiration. The effective portion of the hedging transaction is recognized in AOCI and transferred to earnings using specific identification of each contract when the forecasted hedged transaction takes place or when the forecasted hedged transaction is probable of not
occurring. The ineffective portion of the cash flow hedge is recognized in earnings in the current period. All risk components were taken into account to determine the hedge effectiveness of the cash flow hedges.
We enter into forward power contracts to manage commodity price risk exposure related to our generation of electricity and our sale of retail power to third parties through our subsidiary DPLER. We do not hedge all commodity price risk. We reclassify gains and losses on forward power contracts from AOCI into earnings in those periods in which the contracts settle.
We also enter into interest rate derivative contracts to manage interest rate exposure related to anticipated borrowings of fixed-rate debt. Our anticipated fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. We do not hedge all interest rate exposure. During 2011, interest rate hedging relationships with a notional amount of $200.0 million settled resulting in DPL making a cash payment of $48.1 million ($31.3 million net of tax). As part of the Merger discussed in Note 2, DPL entered into a $425.0 million unsecured term loan agreement with a syndicated bank group on August 24, 2011, in part, to pay the approximately $297.4 million principal amount of DPL’s 6.875% debt that was due in September 2011. The remainder was drawn for other corporate purposes. This agreement is for a three year term expiring on August 24, 2014. See Note 7 for further information. As a result, some of the forecasted transactions originally being hedged are probable of not occurring and therefore approximately $5.1 million ($3.3 million net of tax) has been reclassified to earnings during the period January 1, 2011 through November 27, 2011. Because the interest rate swap had already cash settled as of the Merger date, this hedge had no future value and was not valued as a part of the purchase accounting (See Note 2 for more information). We reclassify gains and losses on interest rate derivative hedges related to debt financings from AOCI into earnings in those periods in which hedged interest payments occur.
The following table provides information for DPL concerning gains or losses recognized in AOCI for the cash flow hedges:
Successor | Predecessor | ||||||||||||||||||||||||||||||||
Years ended December 31, | |||||||||||||||||||||||||||||||||
November 28, 2011 through December 31, 2011 | January 1, 2011 through November 27, 2011 | 2010 | 2009 | ||||||||||||||||||||||||||||||
Interest | Interest | Interest | Interest | ||||||||||||||||||||||||||||||
$ in millions (net of tax) | Power | Rate Hedge | Power | Rate Hedge | Power | Rate Hedge | Power | Rate Hedge | |||||||||||||||||||||||||
Beginning accumulated derivative gain / (loss) in AOCI* | $ | - | $ | - | $ | (1.8 | ) | $ | 21.4 | $ | (1.4 | ) | $ | 14.7 | $ | (0.2 | ) | $ | 17.2 | ||||||||||||||
Net gains / (losses) associated with current period hedging transactions | 0.1 | (0.6 | ) | (1.2 | ) | (57.0 | ) | 3.1 | 9.2 | 2.2 | - | ||||||||||||||||||||||
Net (gains) / losses reclassified to earnings | |||||||||||||||||||||||||||||||||
Interest Expense | - | (0.2 | ) | - | (2.3 | ) | - | (2.5 | ) | - | (2.5 | ) | |||||||||||||||||||||
Revenues | 0.1 | - | 1.1 | - | (3.5 | ) | - | (4.0 | ) | - | |||||||||||||||||||||||
Purchased Power | 0.1 | - | 0.9 | - | - | - | 0.6 | - | |||||||||||||||||||||||||
Ending accumulated derivative gain / (loss) in AOCI* | $ | 0.3 | $ | (0.8 | ) | $ | (1.0 | ) | $ | (37.9 | ) | $ | (1.8 | ) | $ | 21.4 | $ | (1.4 | ) | $ | 14.7 | ||||||||||||
Net gains / (losses) associated with the ineffective portion of the hedging transaction: | |||||||||||||||||||||||||||||||||
Interest expense | $ | - | $ | (0.4 | ) | $ | - | $ | 5.1 | $ | - | $ | - | $ | - | $ | - | ||||||||||||||||
Revenues | $ | - | $ | - | $ | - | $ | - | $ | - | $ | - | $ | - | $ | - | |||||||||||||||||
Portion expected to be reclassified to earnings in the next twelve months** | $ | 0.1 | $ | - | |||||||||||||||||||||||||||||
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) | 36.0 | 21.0 |
* | Approximately $38.9 million of unrealized losses previously deferred into AOCI were removed as a result of purchase accounting. |
See Note 2 of Notes to Consolidated Financial Statements for further details of the preliminary purchase price allocation.
** | The actual amounts that we reclassify from AOCI to earnings related to power can differ from the estimate above due to market price changes. |
The following table shows the fair value and balance sheet classification of DPL’s derivative instruments designated as hedging instruments at December 31, 2011 and 2010.
Fair Values of Derivative Instruments Designated as Hedging Instruments | ||||||||||||||
at December 31, 2011 (Successor) | ||||||||||||||
Balance Sheet Location | Fair Value on | |||||||||||||
$ in millions | Fair Value1 | Netting 2 | Balance Sheet | |||||||||||
Short-term Derivative Positions | ||||||||||||||
Forward Power Contracts in an Asset Position | $ | 1.5 | $ | (0.9 | ) | Other current assets | $ | 0.6 | ||||||
Forward Power Contracts in a Liability Position | (0.2 | ) | - | Other current liabilities | (0.2 | ) | ||||||||
Total short-term cash flow hedges | 1.3 | (0.9 | ) | 0.4 | ||||||||||
Long-term Derivative Positions | ||||||||||||||
Forward Power Contracts in an Asset Position | 0.1 | (0.1 | ) | Other deferred assets | - | |||||||||
Forward Power Contracts in a Liability Position | (2.6 | ) | 1.7 | Other deferred credits | (0.9 | ) | ||||||||
Interest Rate Hedges in a Liability Position | (32.5 | ) | - | Other deferred credits | (32.5 | ) | ||||||||
Total long-term cash flow hedges | (35.0 | ) | 1.6 | (33.4 | ) | |||||||||
Total cash flow hedges | $ | (33.7 | ) | $ | 0.7 | $ | (33.0 | ) |
1 | Includes credit valuation adjustment. |
2 | Includes counterparty and collateral netting. |
Fair Values of Derivative Instruments Designated as Hedging Instruments | ||||||||||||||
at December 31, 2010 (Predecessor) | ||||||||||||||
Balance Sheet Location | Fair Value on | |||||||||||||
$ in millions | Fair Value1 | Netting 2 | Balance Sheet | |||||||||||
Short-term Derivative Positions | ||||||||||||||
Forward Power Contracts in a Liability Position | $ | (2.8 | ) | $ | 1.0 | Other current liabilities | $ | (1.8 | ) | |||||
Interest Rate Hedges in a Liability Position | (6.6 | ) | - | Other current liabilities | (6.6 | ) | ||||||||
Total short-term cash flow hedges | (9.4 | ) | 1.0 | (8.4 | ) | |||||||||
Long-term Derivative Positions | ||||||||||||||
Forward Power Contracts in an Asset Position | 0.2 | (0.2 | ) | Other deferred assets | - | |||||||||
Forward Power Contracts in a Liability Position | (0.2 | ) | 0.1 | Other deferred credits | (0.1 | ) | ||||||||
Interest Rate Hedges in an Asset Position | 20.7 | - | Other deferred assets | 20.7 | ||||||||||
Total long-term cash flow hedges | 20.7 | (0.1 | ) | 20.6 | ||||||||||
Total cash flow hedges | $ | 11.3 | $ | 0.9 | $ | 12.2 |
1 | Includes credit valuation adjustment. |
2 | Includes counterparty and collateral netting. |
Mark to Market Accounting
Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for hedge accounting or the normal purchases and sales exceptions under FASC 815. Accordingly, such contracts are recorded at fair value with changes in the fair value charged or credited to the consolidated statements of results of operations in the period in which the change occurred. This is commonly referred to as “MTM accounting.” Contracts we enter into as part of our risk management program may be settled financially, by physical delivery or net settled with the counterparty. We mark to market FTRs, heating oil futures, forward NYMEX-quality coal contracts and certain forward power contracts.
Certain qualifying derivative instruments have been designated as normal purchases or normal sales contracts, as provided under GAAP. Derivative contracts that have been designated as normal purchases or normal sales under GAAP are not subject to MTM accounting treatment and are recognized in the consolidated statements of results of operations on an accrual basis.
Regulatory Assets and Liabilities
In accordance with regulatory accounting under GAAP, a cost that is probable of recovery in future rates should be deferred as a regulatory asset and a gain that is probable of being returned to customers should be deferred as a regulatory liability. Portions of the derivative contracts that are marked to market each reporting period and
are related to the retail portion of DP&L’s load requirements are included as part of the fuel and purchased power recovery rider approved by the PUCO which began January 1, 2010. Therefore, the Ohio retail customers’ portion of the heating oil futures and the NYMEX-quality coal contracts are deferred as a regulatory asset or liability until the contracts settle. If these unrealized gains and losses are no longer deemed to be probable of recovery through our rates, they will be reclassified into earnings in the period such determination is made.
The following tables show the amount and classification within the consolidated statements of results of operations or balance sheets of the gains and losses on DPL’s derivatives not designated as hedging instruments for the periods November 28, 2011 through December 31, 2011, January 1, 2011 through November 27, 2011, and the years ended December 31, 2010 and 2009.
November 28, 2011 through December 31, 2011 (Successor) | ||||||||||||||||||||
$ in millions | NYMEX Coal | Heating Oil | FTRs | Power | Total | |||||||||||||||
Change in unrealized gain / (loss) | $ | (1.4 | ) | $ | (0.5 | ) | $ | - | $ | (0.8 | ) | $ | (2.7 | ) | ||||||
Realized gain / (loss) | (1.2 | ) | 0.1 | 0.1 | (0.9 | ) | (1.9 | ) | ||||||||||||
Total | $ | (2.6 | ) | $ | (0.4 | ) | $ | 0.1 | $ | (1.7 | ) | $ | (4.6 | ) | ||||||
Recorded on Balance Sheet: | ||||||||||||||||||||
Partners' share of gain / (loss) | $ | (0.3 | ) | $ | - | $ | - | $ | - | $ | (0.3 | ) | ||||||||
Regulatory (asset) / liability | (0.1 | ) | (0.1 | ) | - | - | (0.2 | ) | ||||||||||||
Recorded in Income Statement: gain / (loss) | ||||||||||||||||||||
Revenue | - | - | - | 0.6 | 0.6 | |||||||||||||||
Purchased power | - | - | 0.1 | (2.3 | ) | (2.2 | ) | |||||||||||||
Fuel | (2.2 | ) | (0.3 | ) | - | - | (2.5 | ) | ||||||||||||
O&M | - | - | - | - | - | |||||||||||||||
Total | $ | (2.6 | ) | $ | (0.4 | ) | $ | 0.1 | $ | (1.7 | ) | $ | (4.6 | ) | ||||||
January 1, 2011 through November 27, 2011 (Predecessor) | ||||||||||||||||||||
$ in millions | NYMEX Coal | Heating Oil | FTRs | Power | Total | |||||||||||||||
Change in unrealized gain / (loss) | $ | (50.7 | ) | $ | 0.6 | $ | (0.2 | ) | $ | 0.8 | $ | (49.5 | ) | |||||||
Realized gain / (loss) | 8.7 | 2.2 | (0.6 | ) | (2.7 | ) | 7.6 | |||||||||||||
Total | $ | (42.0 | ) | $ | 2.8 | $ | (0.8 | ) | $ | (1.9 | ) | $ | (41.9 | ) | ||||||
Recorded on Balance Sheet: | ||||||||||||||||||||
Partners' share of gain / (loss) | $ | (25.9 | ) | $ | - | $ | - | $ | - | $ | (25.9 | ) | ||||||||
Regulatory (asset) / liability | (7.0 | ) | 0.1 | - | - | (6.9 | ) | |||||||||||||
Recorded in Income Statement: gain / (loss) | ||||||||||||||||||||
Revenue | - | - | - | (3.8 | ) | (3.8 | ) | |||||||||||||
Purchased power | - | - | (0.8 | ) | 1.9 | 1.1 | ||||||||||||||
Fuel | (9.1 | ) | 2.5 | - | - | (6.6 | ) | |||||||||||||
O&M | - | 0.2 | - | - | 0.2 | |||||||||||||||
Total | $ | (42.0 | ) | $ | 2.8 | $ | (0.8 | ) | $ | (1.9 | ) | $ | (41.9 | ) |
For the Year Ended December 31, 2010 (Predecessor) | ||||||||||||||||||||
$ in millions | NYMEX Coal | Heating Oil | FTRs | Power | Total | |||||||||||||||
Change in unrealized gain / (loss) | $ | 33.5 | $ | 2.8 | $ | (0.6 | ) | $ | 0.1 | $ | 35.8 | |||||||||
Realized gain / (loss) | 3.2 | (1.6 | ) | (1.5 | ) | (0.1 | ) | - | ||||||||||||
Total | $ | 36.7 | $ | 1.2 | $ | (2.1 | ) | $ | - | $ | 35.8 | |||||||||
Recorded on Balance Sheet: | ||||||||||||||||||||
Partners' share of gain / (loss) | $ | 20.1 | $ | - | $ | - | $ | - | $ | 20.1 | ||||||||||
Regulatory (asset) / liability | 4.6 | 1.1 | - | - | 5.7 | |||||||||||||||
Recorded in Income Statement: gain / (loss) | ||||||||||||||||||||
Purchased power | - | - | (2.1 | ) | - | (2.1 | ) | |||||||||||||
Fuel | 12.0 | 0.1 | - | - | 12.1 | |||||||||||||||
O&M | - | - | - | - | - | |||||||||||||||
Total | $ | 36.7 | $ | 1.2 | $ | (2.1 | ) | $ | - | $ | 35.8 |
For the Year Ended December 31, 2009 (Predecessor) | ||||||||||||||||||||
$ in millions | NYMEX Coal | Heating Oil | FTRs | Power | Total | |||||||||||||||
Change in unrealized gain / (loss) | $ | 4.1 | $ | 5.1 | $ | 0.8 | $ | (0.2 | ) | $ | 9.8 | |||||||||
Realized gain / (loss) | 1.1 | (3.1 | ) | (0.4 | ) | - | (2.4 | ) | ||||||||||||
Total | $ | 5.2 | $ | 2.0 | $ | 0.4 | $ | (0.2 | ) | $ | 7.4 | |||||||||
Recorded on Balance Sheet: | ||||||||||||||||||||
Partners' share of gain / (loss) | $ | 1.8 | $ | - | $ | - | $ | - | $ | 1.8 | ||||||||||
Regulatory (asset) / liability | 1.5 | (0.5 | ) | - | - | 1.0 | ||||||||||||||
Recorded in Income Statement: gain / (loss) | ||||||||||||||||||||
Purchased power | - | - | 0.4 | (0.2 | ) | 0.2 | ||||||||||||||
Fuel | 1.9 | 2.3 | - | - | 4.2 | |||||||||||||||
O&M | - | 0.2 | - | - | 0.2 | |||||||||||||||
Total | $ | 5.2 | $ | 2.0 | $ | 0.4 | $ | (0.2 | ) | $ | 7.4 |
The following tables show the fair value and balance sheet classification of DPL’s derivative instruments not designated as hedging instruments at December 31, 2011 and 2010.
Fair Values of Derivative Instruments Not Designated as Hedging Instruments | |||||||||||||||
at December 31, 2011 (Successor) | |||||||||||||||
$ in millions | Fair Value1 | Netting2 | Balance Sheet Location | Fair Value on Balance Sheet | |||||||||||
Short-term Derivative Positions | |||||||||||||||
FTRs in an Asset position | $ | 0.1 | $ | - | Other prepayments and current assets | $ | 0.1 | ||||||||
Forward Power Contracts in an Asset position | 9.9 | - | Other prepayments and current assets | 9.9 | |||||||||||
Forward Power Contracts in a Liability position | (6.5 | ) | 2.6 | Other current liabilities | (3.9 | ) | |||||||||
NYMEX-Quality Coal Forwards in a Liability position | (8.3 | ) | 4.6 | Other current liabilities | (3.7 | ) | |||||||||
Heating Oil Futures in an Asset position | 1.8 | (1.8 | ) | Other prepayments and current assets | - | ||||||||||
Total short-term derivative MTM positions | (3.0 | ) | 5.4 | 2.4 | |||||||||||
Long-term Derivative Positions | |||||||||||||||
Forward Power Contracts in an Asset position | 5.8 | - | Other deferred assets | 5.8 | |||||||||||
Forward Power Contracts in a Liability position | (4.0 | ) | 1.3 | Other deferred credits | (2.7 | ) | |||||||||
NYMEX-Quality Coal Forwards in a Liability position | (6.2 | ) | 6.2 | Other deferred credits | - | ||||||||||
Total long-term derivative MTM positions | (4.4 | ) | 7.5 | 3.1 | |||||||||||
Total MTM Position | $ | (7.4 | ) | $ | 12.9 | $ | 5.5 |
1 | Includes credit valuation adjustment. |
2 | Includes counterparty and collateral netting. |
Fair Values of Derivative Instruments Not Designated as Hedging Instruments | |||||||||||||
at December 31, 2010 (Predecessor) | |||||||||||||
$ in millions | Fair Value1 | Netting2 | Balance Sheet Location | Fair Value on Balance Sheet | |||||||||
Short-term Derivative Positions | |||||||||||||
FTRs in an Asset position | $ | 0.3 | $ | - | Other prepayments and current assets | $ | 0.3 | ||||||
Forward Power Contracts in a Liability position | (0.1 | ) | - | Other current liabilities | (0.1 | ) | |||||||
NYMEX-Quality Coal Forwards in an Asset position | 14.0 | (7.4 | ) | Other prepayments and current assets | 6.6 | ||||||||
Heating Oil Futures in an Asset position | 0.5 | (0.5 | ) | Other prepayments and current assets | - | ||||||||
Total short-term derivative MTM positions | 14.7 | (7.9 | ) | 6.8 | |||||||||
Long-term Derivative Positions | |||||||||||||
NYMEX-Quality Coal Forwards in an Asset position | 23.5 | (14.5 | ) | Other deferred assets | 9.0 | ||||||||
Heating Oil Futures in an Asset position | 1.1 | (1.1 | ) | Other deferred assets | - | ||||||||
Total long-term derivative MTM positions | 24.6 | (15.6 | ) | 9.0 | |||||||||
Total MTM Position | $ | 39.3 | $ | (23.5 | ) | $ | 15.8 |
1 | Includes credit valuation adjustment. |
2 | Includes counterparty and collateral netting. |
Certain of our OTC commodity derivative contracts are under master netting agreements that contain provisions that require our debt to maintain an investment grade credit rating from credit rating agencies. Even though our debt has fallen below investment grade, our counterparties to the derivative instruments have not requested immediate payment or demanded immediate and ongoing full overnight collateralization of the MTM loss.
The aggregate fair value of DPL’s derivative instruments that are in a MTM loss position at December 31, 2011 is $28.0 million. This amount is offset by $16.3 million of collateral posted directly with third parties and in a broker margin account which offsets our loss positions on the forward contracts. This liability position is further offset by the asset position of counterparties with master netting agreements of $4.0 million. If our debt is below investment grade, we could have to post collateral for the remaining $7.7 million.
12. Share-Based Compensation |
In April 2006, DPL’s shareholders approved The DPL Inc. Equity and Performance Incentive Plan (the EPIP) which became immediately effective for a term of ten years. The Compensation Committee of the Board of Directors designated the employees and directors eligible to participate in the EPIP and the times and types of awards to be granted. A total of 4,500,000 shares of DPL common stock had been reserved for issuance under the EPIP.
As a result of the Merger with AES (see Note 2), vesting of all share-based awards was accelerated as of the Merger date. The remaining compensation expense of $5.5 million ($3.6 million after tax) was expensed as of the Merger date.
The following table summarizes share-based compensation expense (note that there is no share-based compensation activity after November 27, 2011 as a result of the Merger):
Predecessor | ||||||||||||
For the years ended | ||||||||||||
December 31, | ||||||||||||
$ in millions | January 1, 2011 through November 27, 2011 | 2010 | 2009 | |||||||||
Restricted stock units | $ | - | $ | - | $ | - | ||||||
Performance shares | 2.4 | 2.1 | 1.8 | |||||||||
Restricted shares | 5.3 | 1.7 | 0.7 | |||||||||
Non-employee directors' RSUs | 0.6 | 0.4 | 0.5 | |||||||||
Management performance shares | 1.8 | 0.5 | 0.7 | |||||||||
Share-based compensation included in | ||||||||||||
Operation and maintenance expense | 10.1 | 4.7 | 3.7 | |||||||||
Income tax expense / (benefit) | (3.5 | ) | (1.6 | ) | (1.3 | ) | ||||||
Total share-based compensation, net of tax | $ | 6.6 | $ | 3.1 | $ | 2.4 |
Share-based awards issued in DPL’s common stock were distributed from treasury stock prior to the Merger; as of the Merger date, remaining share-based awards were distributed in cash in accordance with the Merger Agreement.
Determining Fair Value
Valuation and Amortization Method – We estimated the fair value of performance shares using a Monte Carlo simulation; restricted shares were valued at the closing market price on the day of grant and the Directors’ RSUs were valued at the closing market price on the day prior to the grant date. We amortized the fair value of all awards on a straight-line basis over the requisite service periods, which were generally the vesting periods.
Expected Volatility – Our expected volatility assumptions were based on the historical volatility of DPL common stock. The volatility range captured the high and low volatility values for each award granted based on its specific terms.
Expected Life – The expected life assumption represented the estimated period of time from the grant date until the exercise date and reflected historical employee exercise patterns.
Risk-Free Interest Rate – The risk-free interest rate for the expected term of the award was based on the corresponding yield curve in effect at the time of the valuation for U.S. Treasury bonds having the same term as the expected life of the award, i.e., a five-year bond rate was used for valuing an award with a five year expected life.
Expected Dividend Yield – The expected dividend yield was based on DPL’s current dividend rate, adjusted as necessary to capture anticipated dividend changes and the 12 month average DPL common stock price.
Expected Forfeitures – The forfeiture rate used to calculate compensation expense was based on DPL’s historical experience, adjusted as necessary to reflect special circumstances.
Stock Options
In 2000, DPL’s Board of Directors adopted and DPL’s shareholders approved The DPL Inc. Stock Option Plan. With the approval of the EPIP in April 2006, no new awards were granted under The DPL Inc. Stock Option Plan. Prior to the Merger, all outstanding stock options had been exercised or had expired.
Summarized stock option activity was as follows (note that there is no stock option activity after November 27, 2011 as a result of the Merger):
Predecessor | ||||||||||||
For the years ended | ||||||||||||
December 31, | ||||||||||||
January 1, 2011 through November 27, 2011 | 2010 | 2009 | ||||||||||
Options: | ||||||||||||
Outstanding at beginning of period | 351,500 | 417,500 | 836,500 | |||||||||
Granted | - | - | - | |||||||||
Exercised | (75,500 | ) | (66,000 | ) | (419,000 | ) | ||||||
Expired | (276,000 | ) | - | - | ||||||||
Forfeited | - | - | - | |||||||||
Outstanding at end of period | - | 351,500 | 417,500 | |||||||||
Exercisable at end of period | - | 351,500 | 417,500 | |||||||||
Weighted average option prices per share: | ||||||||||||
Outstanding at beginning of period | $ | 28.04 | $ | 27.16 | $ | 24.64 | ||||||
Granted | $ | - | $ | - | $ | - | ||||||
Exercised | $ | 21.02 | $ | 21.00 | $ | 21.53 | ||||||
Expired | $ | 29.42 | $ | - | $ | - | ||||||
Forfeited | $ | - | $ | - | $ | - | ||||||
Outstanding at end of period | $ | - | $ | 28.04 | $ | 27.16 | ||||||
Exercisable at end of period | $ | - | $ | 28.04 | $ | 27.16 |
The following table reflects information about stock option activity during the period (note that there is no stock option activity after November 27, 2011 as a result of the Merger):
Predecessor | ||||||||||||
For the years ended | ||||||||||||
December 31, | ||||||||||||
$ in millions | January 1, 2011 through November 27, 2011 | 2010 | 2009 | |||||||||
Weighted-average grant date fair value of options granted during the period | $ | - | $ | - | $ | - | ||||||
Intrinsic value of options exercised during the period | $ | 0.7 | $ | 0.5 | $ | 2.2 | ||||||
Proceeds from stock options exercised during the period | $ | 1.6 | $ | 1.4 | $ | 9.0 | ||||||
Excess tax benefit from proceeds of stock options exercised | $ | 0.2 | $ | 0.1 | $ | 0.7 | ||||||
Fair value of shares that vested during the period | $ | - | $ | - | $ | - | ||||||
Unrecognized compensation expense | $ | - | $ | - | $ | - | ||||||
Weighted average period to recognize compensation expense (in years) | - | - | - |
Restricted Stock Units (RSUs)
RSUs were granted to certain key employees prior to 2001. As of the Merger date, there were no RSUs outstanding.
Summarized RSU activity was as follows (note that there is no RSU activity after November 27, 2011 as a result of the Merger):
Predecessor | ||||||||||||
For the years ended | ||||||||||||
December 31, | ||||||||||||
January 1, 2011 through November 27, 2011 | 2010 | 2009 | ||||||||||
RSUs: | ||||||||||||
Outstanding at beginning of period | - | 3,311 | 10,120 | |||||||||
Granted | - | - | - | |||||||||
Dividends | - | - | - | |||||||||
Exercised | - | (3,311 | ) | (6,809 | ) | |||||||
Forfeited | - | - | - | |||||||||
Outstanding at end of period | - | - | 3,311 | |||||||||
Exercisable at end of period | - | - | - |
Performance Shares
Under the EPIP, the Board of Directors adopted a Long-Term Incentive Plan (LTIP) under which DPL granted a targeted number of performance shares of common stock to executives. Grants under the LTIP were awarded based on a Total Shareholder Return Relative to Peers performance. The Total Shareholder Return Relative to Peers is considered a market condition in accordance with the accounting guidance for share-based compensation.
At the Merger date, vesting for all non-vested LTIP performance shares was accelerated on a pro rata basis and such shares were cashed out at the $30.00 per share merger consideration price in accordance with the Merger Agreement.
Summarized Performance Share activity was as follows (note that there is no Performance Share activity after November 27, 2011 as a result of the Merger):
Predecessor | ||||||||||||
For the years ended | ||||||||||||
December 31, | ||||||||||||
January 1, 2011 through November 27, 2011 | 2010 | 2009 | ||||||||||
Performance shares: | ||||||||||||
Outstanding at beginning of year | 278,334 | 237,704 | 156,300 | |||||||||
Granted | 85,093 | 161,534 | 124,588 | |||||||||
Exercised | (198,699 | ) | (91,253 | ) | - | |||||||
Expired | (66,836 | ) | - | (36,445 | ) | |||||||
Forfeited | (97,892 | ) | (29,651 | ) | (6,739 | ) | ||||||
Outstanding at period end | - | 278,334 | 237,704 | |||||||||
Exercisable at period end | - | 66,836 | 47,355 |
The following table reflects information about Performance Share activity during the period (note that there is no Performance Share activity after November 27, 2011 as a result of the Merger):
Predecessor | ||||||||||||
For the years ended | ||||||||||||
December 31, | ||||||||||||
$ in millions | January 1, 2011 through November 27, 2011 | 2010 | 2009 | |||||||||
Weighted-average grant date fair value of performance shares granted during the period | $ | 2.2 | $ | 2.9 | $ | 2.8 | ||||||
Intrinsic value of performance shares exercised during the period | $ | 6.0 | $ | 2.5 | $ | - | ||||||
Proceeds from performance shares exercised during the period | $ | - | $ | - | $ | - | ||||||
Excess tax benefit from proceeds of performance shares exercised | $ | 0.7 | $ | - | $ | - | ||||||
Fair value of performance shares that vested during the period | $ | 4.7 | $ | 1.6 | $ | 1.6 | ||||||
Unrecognized compensation expense | $ | - | $ | 2.4 | $ | 2.1 | ||||||
Weighted average period to recognize compensation expense (in years) | - | 1.7 | 1.7 |
The following table shows the assumptions used in the Monte Carlo Simulation to calculate the fair value of the performance shares granted during the period:
Predecessor | ||||||||||||
For the years ended | ||||||||||||
December 31, | ||||||||||||
January 1, 2011 through November 27, 2011 | 2010 | 2009 | ||||||||||
Expected volatility | 24.0 | % | 24.3 | % | 22.8% - 23.3 | % | ||||||
Weighted-average expected volatility | 24.0 | % | 24.3 | % | 22.8 | % | ||||||
Expected life (years) | 3.0 | 3.0 | 3.0 | |||||||||
Expected dividends | 5.0 | % | 4.5 | % | 5.4% - 5.6 | % | ||||||
Weighted-average expected dividends | 5.0 | % | 4.5 | % | 5.6 | % | ||||||
Risk-free interest rate | 1.2 | % | 1.4 | % | 0.3% - 1.5 | % |
Restricted Shares
Under the EPIP, the Board of Directors granted shares of DPL Restricted Shares to various executives and other key employees. These Restricted Shares were registered in the recipient’s name, carried full voting privileges, received dividends as declared and paid on all DPL common stock and vested after a specified service period.
In July 2008, the Board of Directors granted Restricted Share awards under the EPIP to a select group of management employees. The management Restricted Share awards had a three-year requisite service period, carried full voting privileges and received dividends as declared and paid on all DPL common stock.
On September 17, 2009, the Board of Directors approved a two-part equity compensation award under the EPIP for certain of DPL’s executive officers. The first part was a Restricted Share grant and the second part was a matching Restricted Share grant. These Restricted Share grants generally vested after five years if the participant remained continuously employed with DPL or a DPL subsidiary and if the year-over-year average EPS had increased by at least 1% from 2009 to 2013. Under the matching Restricted Share grant, participants had a three-year period from the date of plan implementation during which they could purchase DPL common stock equal in value to up to two times their 2009 base salary. DPL matched the shares purchased with another grant of Restricted Shares (matching Restricted Share grant). The percentage match by DPL is detailed in the table below. The matching Restricted Share grant would have generally vested over a three-year period if the participant continued to hold the originally purchased shares and remained continuously employed with DPL or a DPL subsidiary. The Restricted Shares were registered in the recipient’s name, carried full voting privileges and received dividends as declared and paid on all DPL common stock.
The matching criteria were:
Value (Cost Basis) of Shares Purchased as a % of 2009 Base Salary | Company % Match of Value of Shares Purchased | |
1% to 25% | 25% | |
>25% to 50% | 50% | |
>50% to 100% | 75% | |
>100% to 200% | 125% |
The matching percentage was applied on a cumulative basis and the resulting Restricted Share grant was adjusted at the end of each calendar quarter. As a result of the Merger, the matching Restricted Share grants were suspended in March 2011.
In February 2011, the Board of Directors granted a targeted number of time-vested Restricted Shares to executives under the Long-Term Incentive Plan (LTIP). These Restricted Shares did not carry voting privileges nor did they receive dividend rights during the vesting period. In addition, a one-year holding period was implemented after the three-year vesting period was completed.
Restricted Shares could only be awarded in DPL common stock.
At the Merger date, vesting for all non-vested Restricted Shares was accelerated and all outstanding shares were cashed out at the $30.00 per share merger consideration price in accordance with the Merger Agreement.
Summarized Restricted Share activity was as follows (note that there is no Restricted Share activity after November 27, 2011 as a result of the Merger):
Predecessor | ||||||||||||
For the years ended | ||||||||||||
December 31, | ||||||||||||
January 1, 2011 through November 27, 2011 | 2010 | 2009 | ||||||||||
Restricted shares: | ||||||||||||
Outstanding at beginning of year | 219,391 | 218,197 | 69,147 | |||||||||
Granted | 67,346 | 42,977 | 159,050 | |||||||||
Exercised | (286,737 | ) | (20,803 | ) | (10,000 | ) | ||||||
Forfeited | - | (20,980 | ) | - | ||||||||
Outstanding at period end | - | 219,391 | 218,197 | |||||||||
Exercisable at period end | - | - | - |
The following table reflects information about Restricted Share activity during the period (note that there is no Restricted Share activity after November 27, 2011 as a result of the Merger):
Predecessor | ||||||||||||
For the years ended | ||||||||||||
December 31, | ||||||||||||
$ in millions | January 1, 2011 through November 27, 2011 | 2010 | 2009 | |||||||||
Weighted-average grant date fair value of restricted shares granted during the period | $ | 1.8 | $ | 1.1 | $ | 4.2 | ||||||
Intrinsic value of restricted shares exercised during the period | $ | 8.6 | $ | 0.4 | $ | 0.3 | ||||||
Proceeds from restricted shares exercised during the period | $ | - | $ | - | $ | - | ||||||
Excess tax benefit from proceeds of restricted shares exercised | $ | 0.5 | $ | 0.1 | $ | - | ||||||
Fair value of restricted shares that vested during the period | $ | 7.5 | $ | 0.6 | $ | 0.3 | ||||||
Unrecognized compensation expense | $ | - | $ | 3.4 | $ | 4.3 | ||||||
Weighted-average period to recognize compensation expense (in years) | - | 2.7 | 3.4 |
Non-Employee Director Restricted Stock Units
Under the EPIP, as part of their annual compensation for service to DPL and DP&L, each non-employee Director received a retainer in RSUs on the date of the shareholders’ annual meeting. The RSUs became non-forfeitable on April 15 of the following year. The RSUs accrued quarterly dividends in the form of additional RSUs. Upon vesting, the RSUs became exercisable and were distributed in DPL common stock, unless the Director chose to defer receipt of the shares until a later date. The RSUs were valued at the closing stock price on the day prior to the grant and the compensation expense was recognized evenly over the vesting period.
At the Merger date, vesting for the remaining non-vested RSUs was accelerated and all vested RSUs (current and prior years) were cashed out at the $30.00 per share merger consideration price in accordance with the Merger Agreement.
The following table reflects information about Restricted Stock Unit activity (note that there is no non-employee Director RSU activity after November 27, 2011 as a result of the Merger):
Predecessor | ||||||||||||
For the years ended | ||||||||||||
December 31, | ||||||||||||
January 1, 2011 through November 27, 2011 | 2010 | 2009 | ||||||||||
Restricted stock units: | ||||||||||||
Outstanding at beginning of year | 16,320 | 20,712 | 15,546 | |||||||||
Granted | 14,392 | 15,752 | 20,016 | |||||||||
Dividends accrued | 3,307 | 2,484 | 1,737 | |||||||||
Vested and exercised | (34,019 | ) | (2,618 | ) | (2,066 | ) | ||||||
Vested, exercised and deferred | - | (20,010 | ) | (14,521 | ) | |||||||
Forfeited | - | - | - | |||||||||
Outstanding at period end | - | 16,320 | 20,712 | |||||||||
Exercisable at period end | - | - | - |
The following table reflects information about non-employee Director RSU activity during the period (note that there is no non-employee Director RSU activity after November 27, 2011 as a result of the Merger):
Predecessor | ||||||||||||
For the years ended | ||||||||||||
December 31, | ||||||||||||
$ in millions | January 1, 2011 through November 27, 2011 | 2010 | 2009 | |||||||||
Weighted-average grant date fair value of non-employee Director RSUs granted during the period | $ | 0.5 | $ | 0.5 | $ | 0.5 | ||||||
Intrinsic value of non-employee Director RSUs exercised during the period | $ | 1.0 | $ | 0.5 | $ | 0.4 | ||||||
Proceeds from non-employee Director RSUs exercised during the period | $ | - | $ | - | $ | - | ||||||
Excess tax benefit from proceeds of non-employee Director RSUs exercised | $ | - | $ | - | $ | - | ||||||
Fair value of non-employee Director RSUs that vested during the period | $ | 1.0 | $ | 0.6 | $ | 0.5 | ||||||
Unrecognized compensation expense | $ | - | $ | 0.1 | $ | 0.1 | ||||||
Weighted-average period to recognize compensation expense (in years) | - | 0.3 | 0.3 |
Management Performance Shares
Under the EPIP, the Board of Directors granted compensation awards for select management employees. The grants had a three year requisite service period and certain performance conditions during the performance period. The management performance shares could only be awarded in DPL common stock.
At the Merger date, vesting for all non-vested management performance shares was accelerated; some of the awards vested at target shares and other awards vested at a pro rata share of target. All vested shares were cashed out at the $30.00 per share merger consideration price in accordance with the Merger Agreement.
Summarized Management Performance Share activity was as follows (note that there is no Management Performance Share activity after November 27, 2011 as a result of the Merger):
Predecessor | ||||||||||||
For the years ended | ||||||||||||
December 31, | ||||||||||||
January 1, 2011 through November 27, 2011 | 2010 | 2009 | ||||||||||
Management performance shares: | ||||||||||||
Outstanding at beginning of year | 104,124 | 84,241 | 39,144 | |||||||||
Granted | 49,510 | 37,480 | 48,719 | |||||||||
Expired | (31,081 | ) | - | - | ||||||||
Exercised | (111,289 | ) | - | - | ||||||||
Forfeited | (11,264 | ) | (17,597 | ) | (3,622 | ) | ||||||
Outstanding at period end | - | 104,124 | 84,241 | |||||||||
Exercisable at period end | - | 31,081 | - |
The following table shows the assumptions used in the Monte Carlo Simulation to calculate the fair value of the Management Performance Shares granted during the period:
Predecessor | ||||||||||||
For the years ended | ||||||||||||
December 31, | ||||||||||||
January 1, 2011 through November 27, 2011 | 2010 | 2009 | ||||||||||
Expected volatility | 24.0 | % | 24.3 | % | 22.8 | % | ||||||
Weighted-average expected volatility | 24.0 | % | 24.3 | % | 22.8 | % | ||||||
Expected life (years) | 3.0 | 3.0 | 3.0 | |||||||||
Expected dividends | 5.0 | % | 4.5 | % | 5.6 | % | ||||||
Weighted-average expected dividends | 5.0 | % | 4.5 | % | 5.6 | % | ||||||
Risk-free interest rate | 1.2 | % | 1.4 | % | 1.5 | % |
The following table reflects information about Management Performance Share activity during the period (note that there is no Management Performance Share activity after November 27, 2011 as a result of the Merger):
Predecessor | ||||||||||||
For the years ended | ||||||||||||
December 31, | ||||||||||||
$ in millions | January 1, 2011 through November 27, 2011 | 2010 | 2009 | |||||||||
Weighted-average grant date fair value of management performance shares granted during the period | $ | 1.3 | $ | 0.9 | $ | 1.0 | ||||||
Intrinsic value of management performance shares exercised during the period | $ | 3.3 | $ | - | $ | - | ||||||
Proceeds from management performance shares exercised during the period | $ | - | $ | - | $ | - | ||||||
Excess tax benefit from proceeds of management performance shares exercised | $ | - | $ | - | $ | - | ||||||
Fair value of management performance shares that vested during the period | $ | 2.7 | $ | 0.9 | $ | - | ||||||
Unrecognized compensation expense | $ | - | $ | 0.9 | $ | 1.0 | ||||||
Weighted-average period to recognize compensation expense (in years) | - | 1.7 | 1.6 |
13. Redeemable Preferred Stock |
DP&L has $100 par value preferred stock, 4,000,000 shares authorized, of which 228,508 were outstanding as of December 31, 2011. DP&L also has $25 par value preferred stock, 4,000,000 shares authorized, none of which was outstanding as of December 31, 2011. The table below details the preferred shares outstanding at December 31, 2011:
Successor | Predecessor | ||||||||||||||||||||
Redemption | Carrying | Carrying | |||||||||||||||||||
Price at | Shares | Value(a) | Value(b) | ||||||||||||||||||
Preferred | December 31, | Outstanding at | December 31, | December 31, | |||||||||||||||||
Stock | 2011 | December 31, | 2011 | 2010 | |||||||||||||||||
Rate | ($ per share) | 2011 | ($ in millions) | ($ in millions) | |||||||||||||||||
DP&L Series A | 3.75 | % | $ | 102.50 | 93,280 | $ | 7.4 | $ | 9.3 | ||||||||||||
DP&L Series B | 3.75 | % | $ | 103.00 | 69,398 | 5.6 | 7.0 | ||||||||||||||
DP&L Series C | 3.90 | % | $ | 101.00 | 65,830 | 5.4 | 6.6 | ||||||||||||||
Total | 228,508 | $ | 18.4 | $ | 22.9 |
(a) | Carrying value is fair value at Merger date - November 28, 2011. |
(b) | Carrying value is par value. |
The DP&L preferred stock may be redeemed at DP&L’s option as determined by its Board of Directors at the per-share redemption prices indicated above, plus cumulative accrued dividends. In addition, DP&L’s
Amended Articles of Incorporation contain provisions that permit preferred stockholders to elect members of the Board of Directors in the event that cumulative dividends on the preferred stock are in arrears in an aggregate amount equivalent to at least four full quarterly dividends. Since this potential redemption-triggering event is not solely within the control of DP&L, the preferred stock is presented on the Balance Sheets as “Redeemable Preferred Stock” in a manner consistent with temporary equity.
As long as any DP&L preferred stock is outstanding, DP&L’s Amended Articles of Incorporation also contain provisions restricting the payment of cash dividends on any of its common stock if, after giving effect to such dividend, the aggregate of all such dividends distributed subsequent to December 31, 1946 exceeds the net income of DP&L available for dividends on its common stock subsequent to December 31, 1946, plus $1.2 million. This dividend restriction has historically not affected DP&L’s ability to pay cash dividends and, as of December 31, 2011, DP&L’s retained earnings of $589.1 million were all available for common stock dividends payable to DPL. We do not expect this restriction to have an effect on the payment of cash dividends in the future. DPL records dividends on preferred stock of DP&L within Interest expense on the Statements of Results of Operations.
14. Common Shareholders’ Equity |
Effective on the Merger date, DPL adopted Amended Articles of Incorporation providing for 1,500 authorized common shares, of which one share is outstanding at December 31, 2011.
On October 27, 2010, the DPL Board of Directors approved a new Stock Repurchase Program that permitted DPL to repurchase up to $200 million of its common stock from time to time in the open market, through private transactions or otherwise. This 2010 Stock Repurchase Program was scheduled to run through December 31, 2013, but was suspended in connection with the Merger with The AES Corporation, discussed further in Note 2.
On October 28, 2009, the DPL Board of Directors approved a Stock Repurchase Program that permitted DPL to use proceeds from the exercise of DPL warrants by warrant holders to repurchase other outstanding DPL warrants or its common stock from time to time in the open market, through private transactions or otherwise. This 2009 Stock Repurchase Program was scheduled to run through June 30, 2012, but was suspended in connection with the Merger with The AES Corporation, discussed further in Note 2. In June 2011, 0.7 million warrants were exercised with proceeds of $14.7 million. Since the Stock Repurchase Program was suspended, the proceeds from the June 2011 exercise of warrants were not used to repurchase stock.
As a result of the Merger involving DPL and AES, the outstanding shares of DPL common stock were converted into the right to receive merger consideration of $30.00 per share. When the remaining warrants were exercised in March 2012, DPL paid the warrant holders an amount equal to $9.00 per warrant, which is the difference between the merger consideration of $30.00 per share of DPL common stock and the exercise price of $21.00 per share. This amount was recorded as a $9 million liability at the Merger date. At December 31, 2011, DPL had 1.0 million outstanding warrants which were exercised in March 2012.
Rights Agreement
DPL’s Rights Agreement, dated as of September 25, 2001, with Computershare Trust Company, N.A. (the “Rights Agreement”) expired in December 2011. The Rights Agreement attached one right to each common share outstanding at the close of business on December 31, 2001. The rights were separate from the common shares and had been exercisable at the exercise price of $130 per right in the event of certain attempted business combinations.
The Rights Agreement was amended as of April 19, 2011, to provide that neither the execution of the Merger Agreement nor the consummation of the transactions contemplated by the Merger Agreement would trigger the provisions of the Rights Agreement.
ESOP
During October 1992, our Board of Directors approved the formation of a Company-sponsored ESOP to fund matching contributions to DP&L’s 401(k) retirement savings plan and certain other payments to eligible full-time employees. ESOP shares used to fund matching contributions to DP&L’s 401(k) vested after either two or three years of service in accordance with the match formula effective for the respective plan match year; other
compensation shares awarded vested immediately. In 1992, the Plan entered into a $90 million loan agreement with DPL in order to purchase shares of DPL common stock in the open market. The leveraged ESOP was funded by an exempt loan, which was secured by the ESOP shares. As debt service payments were made on the loan, shares were released on a pro rata basis. The term loan agreement provided for principal and interest on the loan to be paid prior to October 9, 2007, with the right to extend the loan for an additional ten years. In 2007, the maturity date was extended to October 7, 2017. Effective January 1, 2009, the interest on the loan was amended to a fixed rate of 2.06%, payable annually. Dividends received by the ESOP were used to repay the principal and interest on the ESOP loan to DPL. Dividends on the allocated shares were charged to retained earnings and the share value of these dividends was allocated to participants.
During December 2011, the ESOP Plan was terminated and participant balances were transferred to one of the two DP&L sponsored defined contribution 401(k) plans. On December 5, 2011, the ESOP Trust paid the total outstanding principal and interest of $68 million on the loan with DPL, using the merger proceeds from DPL common stock held within the ESOP suspense account.
Compensation expense recorded, based on the fair value of the shares committed to be released, amounted to zero from November 28, 2011 through December 31, 2011 (successor), $4.8 million from January 1, 2011 through November 27, 2011 (predecessor), $6.7 million in 2010 and $4.0 million in 2009.
For purposes of EPS computations and in accordance with GAAP, we treated ESOP shares as outstanding if they were allocated to participants, released or had been committed to be released. ESOP cumulative shares outstanding for the calculation of EPS were 4.6 million in 2010 and 4.2 million in 2009.
15. Accumulated Other Comprehensive Income (Loss) |
AOCI is included on our balance sheets within the Common shareholders’ equity sections. The following table provides the components that constitute the balance sheet amounts in AOCI at December 31, 2011 and 2010:
DPL | Successor | Predecessor | |||||||
$ in millions | 2011 | 2010 | |||||||
Financial instruments, net of tax | $ | - | $ | 0.6 | |||||
Cash flow hedges, net of tax | (0.5 | ) | 19.6 | ||||||
Pension and postretirement benefits, net of tax | 0.1 | (39.1 | ) | ||||||
Total | $ | (0.4 | ) | $ | (18.9 | ) |
16. EPS |
Basic EPS is based on the weighted-average number of DPL common shares outstanding during the year. Diluted EPS is based on the weighted-average number of DPL common and common-equivalent shares outstanding during the year, except in periods where the inclusion of such common-equivalent shares is anti-dilutive. Excluded from outstanding shares for these weighted-average computations are shares held by DP&L’s Master Trust Plan for deferred compensation and unreleased shares held by DPL’s ESOP.
The common-equivalent shares excluded from the calculation of diluted EPS, because they were anti-dilutive, were not material for the period January 1, 2011, through November 27, 2011 and the years ended December 31, 2010 and 2009. Effective with the Merger with AES, DPL is wholly-owned by AES and earnings per share information is no longer required.
The following illustrates the reconciliation of the numerators and denominators of the basic and diluted EPS computations:
$ and shares in millions except | January 1, 2011 through | For the years ended December 31, | ||||||||||||||||||||||||||||||||||
per share amounts | November 27, 2011 | 2010 | 2009 | |||||||||||||||||||||||||||||||||
Per | Per | Per | ||||||||||||||||||||||||||||||||||
Income | Shares | Share | Income | Shares | Share | Income | Shares | Share | ||||||||||||||||||||||||||||
Basic EPS | $ | 150.5 | 114.5 | $ | 1.31 | $ | 290.3 | 115.6 | $ | 2.51 | $ | 229.1 | 112.9 | $ | 2.03 | |||||||||||||||||||||
�� | ||||||||||||||||||||||||||||||||||||
Effect of Dilutive Securities: | ||||||||||||||||||||||||||||||||||||
Warrants | 0.4 | 0.3 | 1.1 | |||||||||||||||||||||||||||||||||
Stock options, performance and restricted shares | 0.2 | 0.2 | 0.2 | |||||||||||||||||||||||||||||||||
Diluted EPS | $ | 150.5 | 115.1 | $ | 1.31 | $ | 290.3 | 116.1 | $ | 2.50 | $ | 229.1 | 114.2 | $ | 2.01 |
17. Insurance Recovery |
On May 16, 2007, DPL filed a claim with Energy Insurance Mutual (EIM) to recoup legal costs associated with our litigation against certain former executives. On February 15, 2010, after having engaged in both mediation and arbitration, DPL and EIM entered into a settlement agreement resolving all coverage issues and finalizing all obligations in connection with the claim. The proceeds from the settlement amounted to $3.4 million, net of associated expenses, and were recorded as a reduction to operation and maintenance expense during the year ended December 31, 2010.
18. Contractual Obligations, Commercial Commitments and Contingencies |
DPL – Guarantees
In the normal course of business, DPL enters into various agreements with its wholly-owned subsidiaries, DPLE and DPLER and its wholly-owned subsidiary, MC Squared, providing financial or performance assurance to third parties. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to these subsidiaries on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish these subsidiaries’ intended commercial purposes.
At December 31, 2011, DPL had $54.4 million of guarantees to third parties for future financial or performance assurance under such agreements, including $47.1 million of guarantees on behalf of DPLE and DPLER and $7.3 million of guarantees on behalf of MC Squared. The guarantee arrangements entered into by DPL with these third parties cover select present and future obligations of DPLE, DPLER and MC Squared to such beneficiaries and are terminable by DPL upon written notice within a certain time to the beneficiaries. The carrying amount of obligations for commercial transactions covered by these guarantees and recorded in our Consolidated Balance Sheets was $0.1 million and $1.7 million at December 31, 2011 and 2010, respectively.
To date, DPL has not incurred any losses related to the guarantees of DPLE’s, DPLER’s and MC Squared’s obligations and we believe it is remote that DPL would be required to perform or incur any losses in the future associated with any of the above guarantees of DPLE’s, DPLER’s and MC Squared’s obligations.
Equity Ownership Interest
DP&L owns a 4.9% equity ownership interest in an electric generation company which is recorded using the cost method of accounting under GAAP. As of December 31, 2011, DP&L could be responsible for the repayment of 4.9%, or $65.3 million, of a $1,332.3 million debt obligation comprised of both fixed and variable rate securities with maturities between 2013 and 2040. This would only happen if this electric generation company defaulted on its debt payments. As of December 31, 2011, we have no knowledge of such a default.
Contractual Obligations and Commercial Commitments
We enter into various contractual obligations and other commercial commitments that may affect the liquidity of our operations. At December 31, 2011, these include:
Payment Due | ||||||||||||||||||||
$ in millions | Total | Less than 1 Year | 1 - 3 Years | 3 - 5 Years | More Than 5 Years | |||||||||||||||
Long-term debt | $ | 2,599.1 | $ | 0.4 | $ | 895.6 | $ | 450.2 | $ | 1,252.9 | ||||||||||
Interest payments | 1,171.2 | 138.6 | 243.9 | 203.5 | 585.2 | |||||||||||||||
Pension and postretirement payments | 261.1 | 25.6 | 50.8 | 52.1 | 132.6 | |||||||||||||||
Capital leases | 0.7 | 0.3 | 0.4 | - | - | |||||||||||||||
Operating leases | 1.5 | 0.5 | 0.8 | 0.2 | - | |||||||||||||||
Coal contracts (a) | 818.6 | 233.4 | 265.6 | 162.6 | 157.0 | |||||||||||||||
Limestone contracts (a) | 34.8 | 5.8 | 11.6 | 11.6 | 5.8 | |||||||||||||||
Purchase orders and other contractual obligations | 71.3 | 57.5 | 7.8 | 6.0 | - | |||||||||||||||
Total contractual obligations | $ | 4,958.3 | $ | 462.1 | $ | 1,476.5 | $ | 886.2 | $ | 2,133.5 |
(a) | Total at DP&L-operated units |
Long-term debt:
DPL’s long-term debt as of December 31, 2011, consists of DPL’s unsecured notes and unsecured term loan, along with DP&L’s first mortgage bonds, tax-exempt pollution control bonds, capital leases, and the Wright-Patterson Air Force Base note. These long-term debt amounts include current maturities but exclude unamortized debt discounts and fair value adjustments.
DP&L’s long-term debt as of December 31, 2011, consists of first mortgage bonds, tax-exempt pollution control bonds, capital leases, and the Wright-Patterson Air Force Base note. These long-term debt amounts include current maturities but exclude unamortized debt discounts.
See Note 7 for additional information.
Interest payments:
Interest payments are associated with the long-term debt described above. The interest payments relating to variable-rate debt are projected using the interest rate prevailing at December 31, 2011.
Pension and postretirement payments:
As of December 31, 2011, DPL, through its principal subsidiary DP&L, had estimated future benefit payments as outlined in Note 9. These estimated future benefit payments are projected through 2020.
Capital leases:
As of December 31, 2011, DPL, through its principal subsidiary DP&L, had two immaterial capital leases that expire in 2013 and 2014.
Operating leases:
As of December 31, 2011, DPL, through its principal subsidiary DP&L, had several immaterial operating leases with various terms and expiration dates.
Coal contracts:
DPL, through its principal subsidiary DP&L, has entered into various long-term coal contracts to supply the coal requirements for the generating plants it operates. Some contract prices are subject to periodic adjustment and have features that limit price escalation in any given year.
Limestone contracts:
DPL, through its principal subsidiary DP&L, has entered into various limestone contracts to supply limestone used in the operation of FGD equipment at its generating facilities.
Purchase orders and other contractual obligations:
As of December 31, 2011, DPL had various other contractual obligations including non-cancelable contracts to purchase goods and services with various terms and expiration dates.
Reserve for uncertain tax positions:
Due to the uncertainty regarding the timing of future cash outflows associated with our unrecognized tax benefits of $25.0 million, we are unable to make a reliable estimate of the periods of cash settlement with the respective tax authorities and have not included such amounts in the contractual obligations table above.
Contingencies
In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in our Consolidated Financial Statements, as prescribed by GAAP, are adequate in light of the probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims, tax examinations, and other matters, including the matters discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our Consolidated Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided as of December 31, 2011, cannot be reasonably determined.
Environmental Matters
DPL, DP&L and our subsidiaries’ facilities and operations are subject to a wide range of environmental regulations and laws by federal, state and local authorities. As well as imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. In the normal course of business, we have investigatory and remedial activities underway at these facilities to comply, or to determine compliance, with such regulations. We record liabilities for losses that are probable of occurring and can be reasonably estimated. We have estimated liabilities of approximately $3.4 million for environmental matters. We evaluate the potential liability related to
probable losses quarterly and may revise our estimates. Such revisions in the estimates of the potential liabilities could have a material effect on our results of operations, financial condition or cash flows.
We have several pending environmental matters associated with our power plants. Some of these matters could have material adverse impacts on the operation of the power plants; especially the plants that do not have SCR and FGD equipment installed to further control certain emissions. Currently, Hutchings and Beckjord are our only coal-fired power plants that do not have this equipment installed. DP&L owns 100% of the Hutchings plant and a 50% interest in Beckjord Unit 6.
On July 15, 2011, Duke Energy, co-owner at the Beckjord Unit 6 facility, filed their Long-term Forecast Report with the PUCO. The plan indicated that Duke Energy plans to cease production at the Beckjord Station, including our jointly-owned Unit 6, in December 2014. We do not believe that any additional accruals are needed as a result of this decision. We are considering options for Hutchings Station, but have not yet made a final decision. We do not believe that any accruals are needed related to the Hutchings Station.
Environmental Matters Related to Air Quality
Clean Air Act Compliance
In 1990, the federal government amended the CAA to further regulate air pollution. Under the CAA, the USEPA sets limits on how much of a pollutant can be in the ambient air anywhere in the United States. The CAA allows individual states to have stronger pollution controls than those set under the CAA, but states are not allowed to have weaker pollution controls than those set for the whole country. The CAA has a material effect on our operations and such effects are detailed below with respect to certain programs under the CAA.
Cross-State Air Pollution Rule
The Clean Air Interstate Rule (CAIR) final rules were published on May 12, 2005. CAIR created an interstate trading program for annual NOx emission allowances and made modifications to an existing trading program for SO2. Appeals brought by various parties resulted in a decision by the U.S. Court of Appeals for the District of Columbia Circuit on July 11, 2008 to vacate CAIR and its associated Federal Implementation Plan (FIP). On December 23, 2008, the U.S. Court of Appeals issued an order on reconsideration that permits CAIR to remain in effect until the USEPA issues new regulations that would conform to the CAA requirements and the Court’s July 2008 decision.
In an attempt to conform to the Court’s decision, on July 6, 2010, the USEPA proposed the Clean Air Transport Rule (CATR). CATR was finalized as the Cross-State Air Pollution Rule (CSAPR) on July 6, 2011, but subsequent litigation has resulted in CSAPR’s implementation being delayed indefinitely. CSAPR creates four separate trading programs: two SO2 areas (Group 1 and Group 2); and two NOx reduction requirements (annual and ozone season). Group 1 states (16 states including Ohio) will have to meet a 2012 cap and additional reductions in 2014. Group 2 states (7 states) will only have to meet the 2012 cap. We do not believe the rule will have a material effect on our operations in 2012. The Ohio EPA has a State Implementation Plan (SIP) that incorporates the CAIR program requirements, which remain in effect pending judicial review of CSAPR. If CSAPR becomes effective, the USEPA is expected to institute a FIP in lieu of state SIPs and allow for the states to develop SIPs for approval as early as 2013. DP&L is unable to estimate the effect of the new requirements; however, CSAPR could have a material adverse effect on our operations.
Mercury and Other Hazardous Air Pollutants
On May 3, 2011, the USEPA published proposed Maximum Achievable Control Technology (MACT) standards for coal- and oil-fired electric generating units. The standards include new requirements for emissions of mercury and a number of other heavy metals. The EPA Administrator signed the final rule, now called MATS (Mercury and Air Toxics Standards), on December 16, 2011, and the rule was published in the Federal Register on February 16, 2012. Affected electric generating units (EGUs) will have to come into compliance with the new requirements by April 16, 2015, but may be granted an additional year contingent on Ohio EPA approval. DP&L is evaluating the costs that may be incurred to comply with the new requirement; however, MATS could have a material adverse effect on our operations and result in material compliance costs.
On April 29, 2010, the USEPA issued a proposed rule that would reduce emissions of toxic air pollutants from new and existing industrial, commercial and institutional boilers, and process heaters at major and area source facilities. The final rule was published in the Federal Register on March 21, 2011. This regulation affects seven auxiliary boilers used for start-up purposes at DP&L’s generation facilities. The regulations contain emissions limitations, operating limitations and other requirements. The compliance date was originally March 21, 2014.
However, the USEPA has announced that the compliance date for existing boilers will be delayed until a judicial review is no longer pending or until the EPA completes its reconsideration of the rule. In December 2011, the EPA proposed additional changes to this rule and solicited comments. Compliance costs are not expected to be material to DP&L’s operations.
On May 3, 2010, the USEPA finalized the “National Emissions Standards for Hazardous Air Pollutants” for compression ignition (CI) reciprocating internal combustion engines (RICE). The units affected at DP&L are 18 diesel electric generating engines and eight emergency “black start” engines. The existing CI RICE units must comply by May 3, 2013. The regulations contain emissions limitations, operating limitations and other requirements. Compliance costs on DP&L’s operations are not expected to be material.
National Ambient Air Quality Standards
On January 5, 2005, the USEPA published its final non-attainment designations for the National Ambient Air Quality Standard (NAAQS) for Fine Particulate Matter 2.5 (PM 2.5). These designations included counties and partial counties in which DP&L operates and/or owns generating facilities. As of December 31, 2011, DP&L’s Stuart, Killen and Hutchings Stations were located in non-attainment areas for the annual PM 2.5 standard. There is a possibility that these areas will be re-designated as “attainment” for PM 2.5 within the next few quarters. We cannot predict the effect the revisions to the PM 2.5 standard will have on DP&L’s financial condition or results of operations.
On September 16, 2009, the USEPA announced that it would reconsider the 2008 national ground level ozone standard. On September 2, 2011, the USEPA decided to postpone their revisiting of this standard until 2013. DP&L cannot determine the effect of this potential change, if any, on its operations.
Effective April 12, 2010, the USEPA implemented revisions to its primary NAAQS for nitrogen dioxide. This change may affect certain emission sources in heavy traffic areas like the I-75 corridor between Cincinnati and Dayton after 2016. Several of our facilities or co-owned facilities are within this area. DP&L cannot determine the effect of this potential change, if any, on its operations.
Effective August 23, 2010, the USEPA implemented revisions to its primary NAAQS for SO2 replacing the current 24-hour standard and annual standard with a one hour standard. DP&L cannot determine the effect of this potential change, if any, on its operations. No effects are anticipated before 2014.
Regional Haze Program
On May 5, 2004, the USEPA issued its proposed regional haze rule, which addresses how states should determine the Best Available Retrofit Technology (BART) for sources covered under the regional haze rule. Final rules were published July 6, 2005, providing states with several options for determining whether sources in the state should be subject to BART. In the final rule, the USEPA made the determination that CAIR achieves greater progress than BART and may be used by states as a BART substitute. Numerous units owned and operated by us will be affected by BART. We cannot determine the extent of the effect until Ohio determines how BART will be implemented.
Carbon Emissions and Other Greenhouse Gases
In response to a U.S. Supreme Court decision that the USEPA has the authority to regulate CO2 emissions from motor vehicles, the USEPA made a finding that CO2 and certain other GHGs are pollutants under the CAA. Subsequently, under the CAA, USEPA determined that CO2 and other GHGs from motor vehicles threaten the health and welfare of future generations by contributing to climate change. This finding became effective in January 2010. Numerous affected parties have petitioned the USEPA Administrator to reconsider this decision. On April 1, 2010, USEPA signed the “Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards” rule. Under USEPA’s view, this is the final action that renders carbon dioxide and other GHGs “regulated air pollutants” under the CAA.
Under USEPA regulations finalized in May 2010 (referred to as the “Tailoring Rule”), the USEPA began regulating GHG emissions from certain stationary sources in January 2011. The Tailoring rule sets forth criteria for determining which facilities are required to obtain permits for their GHG emissions pursuant to the CAA Prevention of Significant Deterioration and Title V operating permit programs. Under the Tailoring Rule, permitting requirements are being phased in through successive steps that may expand the scope of covered sources over time. The USEPA has issued guidance on what the best available control technology entails for the control of GHGs and individual states are required to determine what controls are required for facilities on a
case-by-case basis. The ultimate impact of the Tailoring Rule to DP&L cannot be determined at this time, but the cost of compliance could be material.
The USEPA plans to propose GHG standards for new and modified electric generating units (EGUs) under CAA subsection 111(b) – and propose and promulgate guidelines for states to address GHG standards for existing EGUs under CAA subsection 111(d) during 2012. These rules may focus on energy efficiency improvements at power plants. We cannot predict the effect of these standards, if any, on DP&L’s operations.
Approximately 98% of the energy we produce is generated by coal. DP&L’s share of CO2 emissions at generating stations we own and co-own is approximately 16 million tons annually. Further GHG legislation or regulation finalized at a future date could have a significant effect on DP&L’s operations and costs, which could adversely affect our net income, cash flows and financial condition. However, due to the uncertainty associated with such legislation or regulation, we cannot predict the final outcome or the financial impact that such legislation or regulation may have on DP&L.
On September 22, 2009, the USEPA issued a final rule for mandatory reporting of GHGs from large sources that emit 25,000 metric tons per year or more of CO2, including electric generating units. DP&L’s first report to the USEPA was submitted prior to the September 30, 2011 due date for 2010 emissions. This reporting rule will guide development of policies and programs to reduce emissions. DP&L does not anticipate that this reporting rule will result in any significant cost or other effect on current operations.
Litigation, Notices of Violation and Other Matters Related to Air Quality
Litigation Involving Co-Owned Plants
On June 20, 2011, the U.S. Supreme Court ruled that the USEAP’s regulation of GHGs under the CAA displaced any right that plaintiffs may have had to seek similar regulation through federal common law litigation in the court system. Although we are not named as a party to these lawsuits, DP&L is a co-owner of coal-fired plants with Duke Energy and AEP (or their subsidiaries) that could have been affected by the outcome of these lawsuits or similar suits that may have been filed against other electric power companies, including DP&L. Because the issue was not squarely before it, the U.S. Supreme Court did not rule against the portion of plaintiffs’ original suits that sought relief under state law.
As a result of a 2008 consent decree entered into with the Sierra Club and approved by the U.S. District Court for the Southern District of Ohio, DP&L and the other owners of the J.M. Stuart generating station are subject to certain specified emission targets related to NOx, SO2 and particulate matter. The consent decree also includes commitments for energy efficiency and renewable energy activities. An amendment to the consent decree was entered into and approved in 2010 to clarify how emissions would be computed during malfunctions. Continued compliance with the consent decree, as amended, is not expected to have a material effect on DP&L’s results of operations, financial condition or cash flows in the future.
Notices of Violation Involving Co-Owned Plants
In November 1999, the USEPA filed civil complaints and NOVs against operators and owners of certain generation facilities for alleged violations of the CAA. Generation units operated by Duke Energy (Beckjord Unit 6) and CSP (Conesville Unit 4) and co-owned by DP&L were referenced in these actions. Although DP&L was not identified in the NOVs, civil complaints or state actions, the results of such proceedings could materially affect DP&L’s co-owned plants.
In June 2000, the USEPA issued a NOV to the DP&L-operated J.M. Stuart generating station (co-owned by DP&L, Duke Energy, and CSP) for alleged violations of the CAA. The NOV contained allegations consistent with NOVs and complaints that the USEPA had brought against numerous other coal-fired utilities in the Midwest. The NOV indicated the USEPA may: (1) issue an order requiring compliance with the requirements of the Ohio SIP; or (2) bring a civil action seeking injunctive relief and civil penalties of up to $27,500 per day for each violation. To date, neither action has been taken. DP&L cannot predict the outcome of this matter.
In December 2007, the Ohio EPA issued a NOV to the DP&L-operated Killen generating station (co-owned by DP&L and Duke Energy) for alleged violations of the CAA. The NOV alleged deficiencies in the continuous
monitoring of opacity. We submitted a compliance plan to the Ohio EPA on December 19, 2007. To date, no further actions have been taken by the Ohio EPA.
On March 13, 2008, Duke Energy, the operator of the Zimmer generating station, received a NOV and a Finding of Violation (FOV) from the USEPA alleging violations of the CAA, the Ohio State Implementation Program (SIP) and permits for the Station in areas including SO2, opacity and increased heat input. A second NOV and FOV with similar allegations was issued on November 4, 2010. Also in 2010, USEPA issued an NOV to Zimmer for excess emissions. DP&L is a co-owner of the Zimmer generating station and could be affected by the eventual resolution of these matters. Duke Energy is expected to act on behalf of itself and the co-owners with respect to these matters. DP&L is unable to predict the outcome of these matters.
Notices of Violation Involving Wholly-Owned Plants
In 2007, the Ohio EPA and the USEPA issued NOVs to DP&L for alleged violations of the CAA at the O.H. Hutchings Station. The NOVs’ alleged deficiencies relate to stack opacity and particulate emissions. Discussions are under way with the USEPA, the U.S. Department of Justice and Ohio EPA. On November 18, 2009, the USEPA issued an NOV to DP&L for alleged NSR violations of the CAA at the O.H. Hutchings Station relating to capital projects performed in 2001 involving Unit 3 and Unit 6. DP&L does not believe that the projects described in the NOV were modifications subject to NSR. DP&L is engaged in discussions with the USEPA and Justice Department to resolve these matters, but DP&L is unable to determine the timing, costs or method by which these issues may be resolved. The Ohio EPA is kept apprised of these discussions.
Environmental Matters Related to Water Quality, Waste Disposal and Ash Ponds
Clean Water Act – Regulation of Water Intake
On July 9, 2004, the USEPA issued final rules pursuant to the Clean Water Act governing existing facilities that have cooling water intake structures. The rules require an assessment of impingement and/or entrainment of organisms as a result of cooling water withdrawal. A number of parties appealed the rules. In April 2009, the U.S. Supreme Court ruled that the USEPA did have the authority to compare costs with benefits in determining best technology available. The USEPA released new proposed regulations on March 28, 2011, published in the Federal Register on April 20, 2011. We submitted comments to the proposed regulations on August 17, 2011. The final rules are expected to be in place by mid-2012. We do not yet know the impact these proposed rules will have on our operations.
Clean Water Act – Regulation of Water Discharge
In December 2006, we submitted an application for the renewal of the Stuart Station NPDES Permit that was due to expire on June 30, 2007. In July 2007, we received a draft permit proposing to continue our authority to discharge water from the station into the Ohio River. On February 5, 2008, we received a letter from the Ohio EPA indicating that they intended to impose a compliance schedule as part of the final Permit, that requires us to implement one of two diffuser options for the discharge of water from the station into the Ohio River as identified in a thermal discharge study completed during the previous permit term. Subsequently, DP&L and the Ohio EPA reached an agreement to allow DP&L to restrict public access to the water discharge area as an alternative to installing one of the diffuser options. Ohio EPA issued a revised draft permit that was received on November 12, 2008. In December 2008, the USEPA requested that the Ohio EPA provide additional information regarding the thermal discharge in the draft permit. In June 2009, DP&L provided information to the USEPA in response to their request to the Ohio EPA. In September 2010, the USEPA formally objected to a revised permit provided by Ohio EPA due to questions regarding the basis for the alternate thermal limitation. In December 2010, DP&L requested a public hearing on the objection, which was held on March 23, 2011. We participated in and presented our position on the issue at the hearing and in written comments submitted on April 28, 2011. In a letter to the Ohio EPA dated September 28, 2011, the USEPA reaffirmed its objection to the revised permit as previously drafted by the Ohio EPA. This reaffirmation stipulated that if the Ohio EPA does not re-draft the permit to address the USEPA’s objection, then the authority for issuing the permit will pass to the USEPA. The Ohio EPA issued another draft permit in December 2011 and a public hearing was held on February 2, 2012. The draft permit would require DP&L, over the 54 months following issuance of a final permit, to take undefined actions to lower the temperature of its discharged water to a level unachievable by the station under its current design or alternatively make other significant modifications to the cooling water system. DP&L submitted comments to the draft permit and is considering legal options. Depending on the outcome of the process, the effects could be material on DP&L’s operation.
In September 2009, the USEPA announced that it will be revising technology-based regulations governing water discharges from steam electric generating facilities. The rulemaking included the collection of information via an industry-wide questionnaire as well as targeted water sampling efforts at selected facilities. Subsequent to the information collection effort, it is anticipated that the USEPA will release a proposed rule by mid-2012 with a final
regulation in place by early 2014. At present, DP&L is unable to predict the impact this rulemaking will have on its operations.
Regulation of Waste Disposal
In September 2002, DP&L and other parties received a special notice that the USEPA considers us to be a PRP for the clean-up of hazardous substances at the South Dayton Dump landfill site. In August 2005, DP&L and other parties received a general notice regarding the performance of a Remedial Investigation and Feasibility Study (RI/FS) under a Superfund Alternative Approach. In October 2005, DP&L received a special notice letter inviting it to enter into negotiations with the USEPA to conduct the RI/FS. No recent activity has occurred with respect to that notice or PRP status. However, on August 25, 2009, the USEPA issued an Administrative Order requiring that access to DP&L’s service center building site, which is across the street from the landfill site, be given to the USEPA and the existing PRP group to help determine the extent of the landfill site’s contamination as well as to assess whether certain chemicals used at the service center building site might have migrated through groundwater to the landfill site. DP&L granted such access and drilling of soil borings and installation of monitoring wells occurred in late 2009 and early 2010. On May 24, 2010, three members of the existing PRP group, Hobart Corporation, Kelsey-Hayes Company and NCR Corporation, filed a civil complaint in the United States District Court for the Southern District of Ohio against DP&L and numerous other defendants alleging that DP&L and the other defendants contributed to the contamination at the South Dayton Dump landfill site and seeking reimbursement of the PRP group’s costs associated with the investigation and remediation of the site. On February 10, 2011, the Court dismissed claims against DP&L that related to allegations that chemicals used by DP&L at its service center contributed to the landfill site’s contamination. The Court, however, did not dismiss claims alleging financial responsibility for remediation costs based on hazardous substances from DP&L that were allegedly directly delivered by truck to the landfill. Discovery, including depositions of past and present DP&L employees, is ongoing. While DP&L is unable to predict the outcome of these matters, if DP&L were required to contribute to the clean-up of the site, it could have a material adverse effect on its operations.
In December 2003, DP&L and other parties received a special notice that the USEPA considers us to be a PRP for the clean-up of hazardous substances at the Tremont City landfill site. Information available to DP&L does not demonstrate that it contributed hazardous substances to the site. While DP&L is unable to predict the outcome of this matter, if DP&L were required to contribute to the clean-up of the site, it could have a material adverse effect on its operations.
On April 7, 2010, the USEPA published an Advance Notice of Proposed Rulemaking announcing that it is reassessing existing regulations governing the use and distribution in commerce of polychlorinated biphenyls (PCBs). While this reassessment is in the early stages and the USEPA is seeking information from potentially affected parties on how it should proceed, the outcome may have a material effect on DP&L. The USEPA has indicated that a proposed rule will be released in late 2012. At present, DP&L is unable to predict the impact this initiative will have on its operations.
Regulation of Ash Ponds
In March 2009, the USEPA, through a formal Information Collection Request, collected information on ash pond facilities across the country, including those at Killen and J.M. Stuart Stations. Subsequently, the USEPA collected similar information for O.H. Hutchings Station.
In August 2010, the USEPA conducted an inspection of the O.H. Hutchings Station ash ponds. In June 2011, the USEPA issued a final report from the inspection including recommendations relative to the O.H. Hutchings Station ash ponds. DP&L is unable to predict whether there will be additional USEPA action relative to DP&L’s proposed plan or the effect on operations that might arise under a different plan.
In June 2011, the USEPA conducted an inspection of the Killen Station ash ponds. DP&L is unable to predict the outcome this inspection will have on its operations.
There has been increasing advocacy to regulate coal combustion byproducts under the Resource Conservation Recovery Act (RCRA). On June 21, 2010, the USEPA published a proposed rule seeking comments on two options under consideration for the regulation of coal combustion byproducts including regulating the material as
a hazardous waste under RCRA Subtitle C or as a solid waste under RCRA Subtitle D. The USEPA anticipates issuing a final rule on this topic in late 2012. DP&L is unable to predict the financial effect of this regulation, but if coal combustion byproducts are regulated as hazardous waste, it is expected to have a material adverse effect on operations.
Notice of Violation involving Co-Owned Plants
On September 9, 2011, DP&L received a notice of violation from the USEPA with respect to its co-owned J.M. Stuart generating station based on a compliance evaluation inspection conducted by the USEPA and Ohio EPA in 2009. The notice alleged non-compliance by DP&L with certain provisions of the RCRA, the Clean Water Act National Pollutant Discharge Elimination System permit program and the station’s storm water pollution prevention plan. The notice requested that DP&L respond with the actions it has subsequently taken or plans to take to remedy the USEPA’s findings and ensure that further violations will not occur. Based on its review of the findings, although there can be no assurance, we believe that the notice will not result in any material effect on DP&L’s results of operations, financial condition or cash flow.
Legal and Other Matters
In February 2007, DP&L filed a lawsuit against a coal supplier seeking damages incurred due to the supplier’s failure to supply approximately 1.5 million tons of coal to two commonly owned plants under a coal supply agreement, of which approximately 570 thousand tons was DP&L’s share. DP&L obtained replacement coal to meet its needs. The supplier has denied liability, and is currently in federal bankruptcy proceedings in which DP&L is participating as an unsecured creditor. DP&L is unable to determine the ultimate resolution of this matter. DP&L has not recorded any assets relating to possible recovery of costs in this lawsuit.
In connection with DP&L and other utilities joining PJM, in 2006, the FERC ordered utilities to eliminate certain charges to implement transitional payments, known as SECA, effective December 1, 2004 through March 31, 2006, subject to refund. Through this proceeding, DP&L was obligated to pay SECA charges to other utilities, but received a net benefit from these transitional payments. A hearing was held and an initial decision was issued in August 2006. A final FERC order on this issue was issued on May 21, 2010 that substantially supports DP&L’s and other utilities’ position that SECA obligations should be paid by parties that used the transmission system during the timeframe stated above. Prior to this final order being issued, DP&L entered into a significant number of bilateral settlement agreements with certain parties to resolve the matter, which by design will be unaffected by the final decision. With respect to unsettled claims, DP&L management has deferred $17.8 million and $15.4 million as of December 31, 2011 and December 31, 2010, respectively, as Other deferred credits representing the amount of unearned income and interest where the earnings process is not complete. The amount at December 31, 2011 includes estimated earnings and interest of $5.2 million. On September 30, 2011, the FERC issued two SECA-related orders that affirmed an earlier order issued in 2010 by denying the rehearing requests that a number of different parties, including DP&L, had filed. These orders are now final, subject to possible appellate court review. These orders do not affect prior settlements that had been reached with other parties that owed SECA revenues to DP&L or were recipients of amounts paid by DP&L. For other parties that had not previously settled with DP&L, the exact timing and amounts of any payments that would be made or received by DP&L under these orders is still uncertain.
The following lawsuits were filed in connection with the Merger (See Item 1A, “Risk Factors,” for additional risks related to the Merger) seeking, among other things, one or more of the following: to rescind the Merger or for rescissory damages, or to commence a sale process and/or obtain an alternative transaction or to recover an unspecified amount of other damages and costs, including attorneys’ fees and expenses, or a constructive trust or an accounting from the individual defendants for benefits they allegedly obtained as a result of their alleged breach of duty. Only the lawsuit filed by the Payne Family Trust noted below remains pending as of the date of this report.
On April 21, 2011, a lawsuit was filed in the Court of Common Pleas of Montgomery County, Ohio, naming DPL and each member of DPL’s board of directors, AES and Dolphin Sub, Inc. as defendants. The lawsuit was a purported class action filed by Patricia A. Heinmullter on behalf of herself and an alleged class of DPL shareholders. On March 22, 2012, the Court entered an order dismissing this lawsuit with prejudice pursuant to a stipulation filed by the parties. Plaintiff had alleged, among other things, that DPL’s directors breached their fiduciary duties in approving the Merger of DPL and AES and that AES and Dolphin Sub, Inc. aided and abetted such breach.
On April 26, 2011, a lawsuit was filed in the United States District Court for the Southern District of Ohio, Western Division (the “District Court”), naming each member of DPL’s board of directors, AES and Dolphin Sub, Inc. as defendants and naming DPL as a nominal defendant. The lawsuit filed by Stephen Kubiak is a purported class action on behalf of plaintiff and an alleged class of DPL shareholders and a purported derivative action on behalf of DPL. Plaintiff alleges, among other things, that DPL’s directors breached their fiduciary duties in approving the Merger of DPL and AES and that AES and Dolphin Sub, Inc. aided and abetted such breach.
On April 27, 2011, another lawsuit was filed in the Court of Common Pleas of Montgomery County, Ohio, naming DPL, each member of DPL’s board of directors, AES and Dolphin Sub, Inc. as defendants. The lawsuit filed by Laurence D. Paskowitz was a purported class action on behalf of plaintiff and an alleged class of DPL shareholders. On March 21, 2012, the Court entered an order dismissing this lawsuit with prejudice pursuant to a stipulation filed by the parties. Plaintiff had alleged, among other things, that DPL’s directors breached their fiduciary duties in approving the Merger of DPL and AES and that DPL, AES and Dolphin Sub, Inc. aided and abetted such breach.
On April 28, 2011, a lawsuit was filed in the Court of Common Pleas of Montgomery County, Ohio, naming DPL and each member of DPL’s board of directors as defendants. The lawsuit filed by Payne Family Trust is a purported class action on behalf of plaintiff and an alleged class of DPL shareholders. Plaintiff alleges, among other things, that DPL’s directors breached their fiduciary duties in approving the Merger of DPL and AES.
On May 4, 2011, a lawsuit was filed in the District Court naming DPL, each member of DPL’s board of directors, AES and Dolphin Sub, Inc. as defendants. The lawsuit filed by Patrick Nichting is a purported class action on behalf of plaintiff and an alleged class of DPL shareholders and a purported derivative action on behalf of DPL. Plaintiff alleges, among other things, that DPL’s directors breached their fiduciary duties in approving the Merger of DPL and AES and that DPL, AES and Dolphin Sub, Inc. aided and abetted such breach.
On May 20, 2011, a lawsuit was filed in the District Court naming DPL, each member of DPL’s board of directors, AES and Dolphin Sub, Inc. as defendants. The lawsuit filed by Ralph B. Holtmann and Catherine P. Holtmann is a purported class action on behalf of plaintiffs and an alleged class of DPL shareholders. Plaintiffs allege, among other things, that DPL’s directors breached their fiduciary duties in approving the Merger of DPL and AES and that DPL, AES and Dolphin Sub, Inc. aided and abetted such breach.
On May 24, 2011, a lawsuit was filed in the Court of Common Pleas of Montgomery County, Ohio, naming each member of DPL’s board of directors and AES as defendants and naming DPL as a nominal defendant. The lawsuit filed by Maxine Levy was a purported class action on behalf of plaintiff and an alleged class of DPL shareholders and a purported derivative action on behalf of DPL. On March 22, 2012, the Court entered an order dismissing this lawsuit with prejudice pursuant to a stipulation filed by the parties. Plaintiff had alleged, among other things, that DPL’s directors breached their fiduciary duties in approving the Merger of DPL and AES and that AES and Dolphin Sub, Inc. aided and abetted such breach.
On June 13, 2011, the three actions in the District Court were consolidated. On June 14, 2011, the District Court granted Plaintiff Nichting’s motion to appoint lead and liaison counsel. On June 30, 2011, plaintiffs in the consolidated federal action filed an amended complaint that added claims based on alleged omissions in the preliminary proxy statement that DPL filed on June 22, 2011 (the “Preliminary Proxy Statement”). Plaintiffs, in their individual capacity only, asserted a claim against DPL and its directors under Section 14(a) of the Securities Exchange Act of 1934 (the “Exchange Act”) for purported omissions in the Preliminary Proxy Statement and a claim against DPL’s directors for control person liability under Section 20(a) of the Exchange Act. In addition, plaintiffs purported to assert state law claims directly on behalf of Plaintiffs and an alleged class of DPL shareholders and derivatively on behalf of DPL. Plaintiffs alleged, among other things, that DPL’s directors breached their fiduciary duties in approving the Merger Agreement for the Merger of DPL and AES and that DPL, AES and Dolphin Sub, Inc. aided and abetted such breach.
On February 24, 2012, the District Court entered an order approving a settlement between DPL, DPL’s directors, AES and Dolphin Sub, Inc. and the plaintiffs in the consolidated federal action. The settlement resolves all pending federal court litigation related to the Merger, including the Kubiak, Holtmann and Nichting actions, results in the release by the plaintiffs and the proposed settlement class of all claims that were or could
have been brought challenging any aspect of the Merger Agreement, the Merger and any disclosures made in connection therewith and provides for an immaterial award of plaintiffs’ attorneys’ fees and expenses.
19. Business Segments |
DPL operates through two segments consisting of the operations of two of its wholly-owned subsidiaries, DP&L (Utility segment) and DPLER (Competitive Retail segment) and DPLER’s wholly-owned subsidiary, MC Squared (Competitive Retail segment). This is how we view our business and make decisions on how to allocate resources and evaluate performance.
The Utility segment is comprised of DP&L’s electric generation, transmission and distribution businesses which generate and sell electricity to residential, commercial, industrial and governmental customers. Electricity for the segment’s 24 county service area is primarily generated at eight coal-fired power plants and is distributed to more than 500,000 retail customers who are located in a 6,000 square mile area of West Central Ohio. DP&L also sells electricity to DPLER and any excess energy and capacity is sold into the wholesale market. DP&L’s transmission and distribution businesses are subject to rate regulation by federal and state regulators while rates for its generation business are deemed competitive under Ohio law.
The Competitive Retail segment is DPLER’s and MC Squared’s competitive retail electric service businesses which sell retail electric energy under contract to residential, commercial, industrial and governmental customers who have selected DPLER or MC Squared as their alternative electric supplier. The Competitive Retail segment sells electricity to approximately 40,000 customers currently located throughout Ohio and in Illinois. In February 2011, DPLER purchased MC Squared, a Chicago-based retail electricity supplier, which serves approximately 3,157 customers in Northern Illinois. Due to increased competition in Ohio, since 2010 we have increased the number of employees and resources assigned to manage the Competitive Retail segment and increased its marketing to customers. The Competitive Retail segment’s electric energy used to meet its sales obligations was purchased from DP&L and PJM. During 2010, we implemented a new wholesale agreement between DP&L and DPLER. Under this agreement, intercompany sales from DP&L to DPLER were based on the market prices for wholesale power. In periods prior to 2010, DPLER’s purchases from DP&L were transacted at prices that approximated DPLER’s sales prices to its end-use retail customers. The Competitive Retail segment has no transmission or generation assets. The operations of the Competitive Retail segment are not subject to cost-of-service rate regulation by federal or state regulators.
Included within the “Other” column are other businesses that do not meet the GAAP requirements for disclosure as reportable segments as well as certain corporate costs which include interest expense on DPL’s debt.
Management evaluates segment performance based on gross margin. The accounting policies of the reportable segments are the same as those described in Note 1 – Overview and Summary of Significant Accounting Policies. Intersegment sales and profits are eliminated in consolidation.
The following tables present financial information for each of DPL’s reportable business segments:
$ in millions | Utility | Competitive Retail | Other | Adjustments and Eliminations | DPL Consolidated | |||||||||||||||
November 28, 2011 through December 31, 2011 (Successor) | ||||||||||||||||||||
Revenues from external customers | $ | 116.2 | $ | 38.2 | $ | 2.5 | $ | - | $ | 156.9 | ||||||||||
Intersegment revenues | 27.8 | - | 0.3 | (28.1 | ) | - | ||||||||||||||
Total revenues | 144.0 | 38.2 | 2.8 | (28.1 | ) | 156.9 | ||||||||||||||
Fuel | 34.5 | - | 1.3 | - | 35.8 | |||||||||||||||
Purchased power | 31.0 | 33.4 | - | (27.7 | ) | 36.7 | ||||||||||||||
Gross margin (a) | 78.5 | 4.8 | (10.1 | ) | (0.4 | ) | 72.8 | |||||||||||||
Depreciation and amortization | 12.7 | - | (1.1 | ) | - | 11.6 | ||||||||||||||
Interest expense | 2.8 | 0.1 | 8.8 | (0.2 | ) | 11.5 | ||||||||||||||
Income tax expense (benefit) | 5.8 | 1.1 | (6.3 | ) | - | 0.6 | ||||||||||||||
Net income (loss) | $ | 45.8 | $ | 1.7 | $ | (53.7 | ) | $ | - | $ | (6.2 | ) | ||||||||
Total assets | $ | 3,525.7 | $ | 69.9 | $ | 2,501.5 | $ | - | $ | 6,097.1 | ||||||||||
Capital expenditures | $ | 30.5 | $ | - | $ | - | $ | - | $ | 30.5 | ||||||||||
January 1, 2011 through November 27, 2011 (Predecessor) | ||||||||||||||||||||
Revenues from external customers | $ | 1,234.5 | $ | 387.2 | $ | 49.2 | $ | - | $ | 1,670.9 | ||||||||||
Intersegment revenues | 299.2 | - | 3.7 | (302.9 | ) | - | ||||||||||||||
Total revenues | 1,533.7 | 387.2 | 52.9 | (302.9 | ) | 1,670.9 | ||||||||||||||
Fuel | 346.1 | - | 9.7 | - | 355.8 | |||||||||||||||
Purchased power | 370.6 | 330.5 | 2.7 | (299.2 | ) | 404.6 | ||||||||||||||
Gross margin (a) | 817.0 | 56.7 | 40.5 | (3.7 | ) | 910.5 | ||||||||||||||
Depreciation and amortization | 122.2 | 0.6 | 6.6 | - | 129.4 | |||||||||||||||
Interest expense | 35.4 | 0.2 | 23.4 | (0.3 | ) | 58.7 | ||||||||||||||
Income tax expense (benefit) | 98.4 | 16.7 | (13.1 | ) | - | 102.0 | ||||||||||||||
Net income (loss) | $ | 147.4 | $ | 24.1 | $ | (21.0 | ) | $ | - | $ | 150.5 | |||||||||
Capital expenditures | $ | 174.0 | $ | - | $ | 0.2 | $ | - | $ | 174.2 |
(a) | For purposes of discussing operating results, we present and discuss gross margins. This format is useful to investors because it allows analysis and comparability of operating trends and includes the same information that is used by management to make decisions regarding our financial performance. |
$ in millions | Utility | Competitive Retail | Other | Adjustments and Eliminations | DPL Consolidated | |||||||||||||||
Year Ended December 31, 2010 (Predecessor) | ||||||||||||||||||||
Revenues from external customers | $ | 1,500.3 | $ | 277.0 | $ | 54.1 | $ | - | $ | 1,831.4 | ||||||||||
Intersegment revenues | 238.5 | - | 4.5 | (243.0 | ) | - | ||||||||||||||
Total revenues | 1,738.8 | 277.0 | 58.6 | (243.0 | ) | 1,831.4 | ||||||||||||||
Fuel | 371.9 | - | 12.0 | - | 383.9 | |||||||||||||||
Purchased power | 383.5 | 238.5 | 3.9 | (238.5 | ) | 387.4 | ||||||||||||||
Gross margin (a) | 983.4 | 38.5 | 42.7 | (4.5 | ) | 1,060.1 | ||||||||||||||
Depreciation and amortization | 130.7 | 0.2 | 8.5 | - | 139.4 | |||||||||||||||
Interest expense | 37.1 | - | 33.5 | - | 70.6 | |||||||||||||||
Income tax expense (benefit) | 135.2 | 10.5 | (2.7 | ) | - | 143.0 | ||||||||||||||
Net income (loss) | $ | 277.7 | $ | 18.8 | $ | (3.5 | ) | $ | (2.7 | ) | $ | 290.3 | ||||||||
Total assets | $ | 3,475.4 | $ | 35.7 | $ | 302.2 | $ | - | $ | 3,813.3 | ||||||||||
Capital expenditures | $ | 148.2 | $ | - | $ | 3.2 | $ | - | $ | 151.4 | ||||||||||
Year Ended December 31, 2009 (Predecessor) | ||||||||||||||||||||
Revenues from external customers | $ | 1,436.0 | $ | 65.5 | $ | 37.8 | $ | - | $ | 1,539.3 | ||||||||||
Intersegment revenues | 64.8 | - | 3.8 | (68.6 | ) | - | ||||||||||||||
Total revenues | 1,500.8 | 65.5 | 41.6 | (68.6 | ) | 1,539.3 | ||||||||||||||
Fuel | 323.6 | - | 6.8 | - | 330.4 | |||||||||||||||
Purchased power | 259.2 | 64.8 | 1.0 | (64.8 | ) | 260.2 | ||||||||||||||
Gross margin (a) | 918.0 | 0.7 | 33.7 | (3.6 | ) | 948.8 | ||||||||||||||
Depreciation and amortization | 135.5 | 0.1 | 9.9 | - | 145.5 | |||||||||||||||
Interest expense | 38.5 | - | 44.5 | - | 83.0 | |||||||||||||||
Income tax expense (benefit) | 124.5 | (0.8 | ) | (11.2 | ) | - | 112.5 | |||||||||||||
Net income (loss) | $ | 258.9 | $ | (2.7 | ) | $ | (21.4 | ) | $ | (5.7 | ) | $ | 229.1 | |||||||
Total assets | $ | 3,457.4 | $ | 6.6 | $ | 177.7 | $ | - | $ | 3,641.7 | ||||||||||
Capital expenditures | $ | 144.0 | $ | - | $ | 1.3 | $ | - | $ | 145.3 |
(a) | For purposes of discussing operating results, we present and discuss gross margins. This format is useful to investors because it allows analysis and comparability of operating trends and includes the same information that is used by management to make decisions regarding our financial performance. |
20. Selected Quarterly Information (Unaudited) |
DPL
For the 2011 periods ended (a) | |||||||||||||||||||||
$ in millions except per share amount and common stock market price | Predecessor | Successor | |||||||||||||||||||
March 31 | June 30 | September 30 | November 27 | December 31 | |||||||||||||||||
Revenues | $ | 480.6 | $ | 433.4 | $ | 497.5 | $ | 259.4 | $ | 156.9 | |||||||||||
Operating income | $ | 100.9 | $ | 65.8 | $ | 112.9 | $ | 48.2 | $ | 6.1 | |||||||||||
Net income (loss) | $ | 43.5 | $ | 31.7 | $ | 67.1 | $ | 8.2 | $ | (6.2 | ) | ||||||||||
Earnings per share of common stock: | |||||||||||||||||||||
Basic | $ | 0.38 | $ | 0.28 | $ | 0.58 | $ | 0.07 | N/A | ||||||||||||
Diluted | $ | 0.38 | $ | 0.28 | $ | 0.58 | $ | 0.07 | N/A | ||||||||||||
Dividends declared per share | $ | 0.3325 | $ | 0.3325 | $ | 0.3325 | $ | 0.5400 | N/A |
(a) | Periods ended March 31, June 30, and September 30 represent three months then ended. Period ended November 27represents approximately two months then ended and period ended December 31, represents approximately one month then ended. |
For the 2010 quarters ended | |||||||||||||||||
$ in millions except per share amount and common stock market price | Predecessor | ||||||||||||||||
March 31 | June 30 | September 30 | December 31 | ||||||||||||||
Revenues | $ | 437.0 | $ | 434.1 | $ | 502.3 | $ | 458.0 | |||||||||
Operating income | $ | 126.0 | $ | 109.3 | $ | 144.6 | $ | 124.5 | |||||||||
Net income | $ | 71.0 | $ | 61.4 | $ | 86.4 | $ | 71.5 | |||||||||
Earnings per share of common stock: | |||||||||||||||||
Basic | $ | 0.61 | $ | 0.53 | $ | 0.75 | $ | 0.62 | |||||||||
Diluted | $ | 0.61 | $ | 0.53 | $ | 0.74 | $ | 0.62 | |||||||||
Dividends declared and paid per share | $ | 0.3025 | $ | 0.3025 | $ | 0.3025 | $ | 0.3025 | |||||||||
Common stock market price | - High | $ | 28.47 | $ | 28.18 | $ | 26.65 | $ | 27.51 | ||||||||
- Low | $ | 26.51 | $ | 23.80 | $ | 23.95 | $ | 25.33 |
DPL Inc.
VALUATION AND QUALIFYING ACCOUNTS
For the period November 28, 2011 through December 31, 2011, the period January 1,
2011 through November 27, 2011, and the years ended December 31, 2010 and 2009
$ in thousands | ||||||||||||||||
Balance at | ||||||||||||||||
Beginning | Deductions | Balance at | ||||||||||||||
Description | of Period | Additions | (1) | End of Period | ||||||||||||
November 28, 2011 through December 31, 2011 (Successor): | ||||||||||||||||
Deducted from accounts receivable - Provision for uncollectible accounts | $ | 1,062 | $ | 643 | $ | 569 | $ | 1,136 | ||||||||
Deducted from deferred tax assets - Valuation allowance for deferred tax assets | $ | 7,086 | $ | 349 | $ | 733 | $ | 6,702 | ||||||||
January 1, 2011 through November 27, 2011 (Predecessor): | ||||||||||||||||
Deducted from accounts receivable - Provision for uncollectible accounts | $ | 871 | $ | 5,716 | $ | 5,525 | $ | 1,062 | ||||||||
Deducted from deferred tax assets - Valuation allowance for deferred tax assets | $ | 13,079 | $ | 2,705 | $ | 8,698 | $ | 7,086 | ||||||||
2010 (Predecessor): | ||||||||||||||||
Deducted from accounts receivable - Provision for uncollectible accounts | $ | 1,101 | $ | 4,148 | $ | 4,378 | $ | 871 | ||||||||
Deducted from deferred tax assets - Valuation allowance for deferred tax assets | $ | 11,955 | $ | 1,124 | $ | - | $ | 13,079 | ||||||||
2009 (Predecessor): | ||||||||||||||||
Deducted from accounts receivable - Provision for uncollectible accounts | $ | 1,084 | $ | 5,168 | $ | 5,151 | $ | 1,101 | ||||||||
Deducted from deferred tax assets - Valuation allowance for deferred tax assets | $ | 10,685 | $ | 1,270 | $ | - | $ | 11,955 |
(1) | Amounts written off, net of recoveries of accounts previously written off. |
FINANCIAL STATEMENTS
DPL INC.
Three Months Ended | Six Months Ended | |||||||||||||||||
June 30, | June 30, | |||||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||||
$ in millions except per share amounts | Successor | Predecessor | Successor | Predecessor | ||||||||||||||
Revenues | $ | 382.0 | $ | 433.3 | $ | 816.0 | $ | 913.9 | ||||||||||
Cost of revenues: | ||||||||||||||||||
Fuel | 68.9 | 92.1 | 166.3 | 191.9 | ||||||||||||||
Purchased power | 80.3 | 113.6 | 175.1 | 234.4 | ||||||||||||||
Amortization of intangibles | 19.2 | - | 47.0 | - | ||||||||||||||
Total cost of revenues | 168.4 | 205.7 | 388.4 | 426.3 | ||||||||||||||
Gross margin | 213.6 | 227.6 | 427.6 | 487.6 | ||||||||||||||
Operating expenses: | ||||||||||||||||||
Operation and maintenance | 103.8 | 106.8 | 205.5 | 206.2 | ||||||||||||||
Depreciation and amortization | 31.1 | 35.1 | 62.5 | 70.2 | ||||||||||||||
General taxes | 21.3 | 19.9 | 43.0 | 44.6 | ||||||||||||||
Total operating expenses | 156.2 | 161.8 | 311.0 | 321.0 | ||||||||||||||
Operating income | 57.4 | 65.8 | 116.6 | 166.6 | ||||||||||||||
Other income / (expense), net: | ||||||||||||||||||
Investment income | 0.2 | 0.1 | 0.3 | 0.2 | ||||||||||||||
Interest expense | (32.4 | ) | (17.6 | ) | (62.0 | ) | (34.5 | ) | ||||||||||
Charge for early redemption of debt | - | - | - | (15.3 | ) | |||||||||||||
Other income / (deductions) | (0.9 | ) | (0.3 | ) | (1.2 | ) | (0.7 | ) | ||||||||||
Total other income / (expense), net | (33.1 | ) | (17.8 | ) | (62.9 | ) | (50.3 | ) | ||||||||||
Earnings before income tax | 24.3 | 48.0 | 53.7 | 116.3 | ||||||||||||||
Income tax expense | 12.4 | 16.3 | 20.1 | 41.1 | ||||||||||||||
Net income | $ | 11.9 | $ | 31.7 | $ | 33.6 | $ | 75.2 | ||||||||||
Average number of common shares outstanding (millions): | ||||||||||||||||||
Basic | N/A | 114.2 | N/A | 114.1 | ||||||||||||||
Diluted | N/A | 114.9 | N/A | 114.7 | ||||||||||||||
Earnings per share of common stock: | ||||||||||||||||||
Basic | N/A | $ | 0.28 | N/A | $ | 0.66 | ||||||||||||
Diluted | N/A | $ | 0.28 | N/A | $ | 0.66 | ||||||||||||
Dividends paid per share of common stock | N/A | $ | 0.3325 | N/A | $ | 0.6650 |
See Notes to Condensed Consolidated Financial Statements.
These interim statements are unaudited.
Three Months Ended | Six Months Ended | |||||||||||||||||
June 30, | June 30, | |||||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||||
$ in millions | Successor | Predecessor | Successor | Predecessor | ||||||||||||||
Net income (loss) | $ | 11.9 | $ | 31.7 | $ | 33.6 | $ | 75.2 | ||||||||||
Available-for-sale securities activity: | ||||||||||||||||||
Change in fair value of available-for-sale securities, | ||||||||||||||||||
net of income base benefit / (expense) of $0.1 and $0.0, | ||||||||||||||||||
respectively, for the three months and $(0.2) and $0.0, | ||||||||||||||||||
respectively for the six months | (0.1 | ) | - | 0.3 | - | |||||||||||||
Total change in fair value of available-for-sale securities | (0.1 | ) | - | 0.3 | - | |||||||||||||
Derivative activity: | ||||||||||||||||||
Change in derivative fair value, | ||||||||||||||||||
net of income tax expense of $7.4 and $6.0, respectively, | ||||||||||||||||||
for the three months and $3.3 and $5.4, respectively, | ||||||||||||||||||
for the six months | (13.4 | ) | (11.3 | ) | (5.8 | ) | (10.1 | ) | ||||||||||
Reclassification of earnings, net of income tax (expense) / benefit | ||||||||||||||||||
of $0.0 and $(1.0), respectively, for the three months | ||||||||||||||||||
and $0.7 and $(1.3), respectively, for the six months | 0.1 | 1.3 | (0.8 | ) | 1.3 | |||||||||||||
Total change in fair value of derivatives | (13.3 | ) | (10.0 | ) | (6.6 | ) | (8.8 | ) | ||||||||||
Pension and postretirement activity: | ||||||||||||||||||
Reclassification to earnings, net of income tax benefit / (expense) | ||||||||||||||||||
of $0.0 and $(0.3), respectively, for the three months and $0.0 | ||||||||||||||||||
and $(0.8), respectively for the six months | (0.1 | ) | 0.4 | (0.1 | ) | 1.6 | ||||||||||||
Total change in unfunded pension obligation | (0.1 | ) | 0.4 | (0.1 | ) | 1.6 | ||||||||||||
Other comprehensive income / (loss) | (13.5 | ) | (9.6 | ) | (6.4 | ) | (7.2 | ) | ||||||||||
Net comprehensive income / (loss) | $ | (1.6 | ) | $ | 22.1 | $ | 27.2 | $ | 68.0 |
See Notes to Condensed Consolidated Financial Statements.
These interim statements are unaudited.
DPL INC.
Six Months Ended | |||||||||
June 30, | |||||||||
2012 | 2011 | ||||||||
$ in millions | Successor | Predecessor | |||||||
Cash flows from operating activities: | |||||||||
Net income | $ | 33.6 | $ | 75.2 | |||||
Adjustments to reconcile Net income to Net cash provided by | |||||||||
operating activities: | |||||||||
Depreciation and amortization | 62.5 | 70.2 | |||||||
Amortization of other assets | 47.0 | - | |||||||
Amortization of debt market value adjustments | (9.5 | ) | - | ||||||
Deferred income taxes | (3.1 | ) | 37.5 | ||||||
Charge for early redemption of debt | - | 15.3 | |||||||
Changes in certain assets and liabilities: | |||||||||
Accounts receivable | 9.6 | 19.5 | |||||||
Inventories | (1.2 | ) | 1.2 | ||||||
Prepaid taxes | 0.3 | (20.7 | ) | ||||||
Taxes applicable to subsequent years | 40.7 | 31.8 | |||||||
Deferred regulatory costs, net | 0.1 | 8.9 | |||||||
Accounts payable | 7.9 | (5.9 | ) | ||||||
Accrued taxes payable | (50.6 | ) | (33.4 | ) | |||||
Accrued interest payable | 1.5 | 2.0 | |||||||
Pension, retiree and other benefits | 4.6 | (42.7 | ) | ||||||
Unamortized investment tax credit | (0.1 | ) | (1.4 | ) | |||||
Insurance and claims costs | - | 3.7 | |||||||
Other | (0.2 | ) | 23.9 | ||||||
Net cash provided by operating activities | 143.1 | 185.1 | |||||||
Cash flows from investing activities: | |||||||||
Capital expenditures | (110.5 | ) | (91.4 | ) | |||||
Purchase of MC Squared | - | (8.2 | ) | ||||||
Purchases of short-term investments and securities | - | (1.7 | ) | ||||||
Sales of short-term investments and securities | - | 70.9 | |||||||
Other investing activities, net | - | 1.8 | |||||||
Net cash used for investing activities | (110.5 | ) | (28.6 | ) | |||||
Cash flows from financing activities: | |||||||||
Dividends paid on common stock | (45.0 | ) | (76.4 | ) | |||||
Contributions to additional paid-in capital from parent | 0.3 | - | |||||||
Payment to former warrant holders | (9.0 | ) | - | ||||||
Retirement of long-term debt | (0.1 | ) | - | ||||||
Early redemption of Capital Trust II notes | - | (122.0 | ) | ||||||
Premium paid for early redemption of debt | - | (12.2 | ) | ||||||
Payment of MC Squared debt | - | (13.5 | ) | ||||||
Withdrawals from revolving credit facilities | - | 50.0 | |||||||
Repayment of borrowing from revolving credit facilities | - | (50.0 | ) | ||||||
Exercise of stock options | - | 1.4 | |||||||
Exercise of warrants | - | 14.7 | |||||||
Tax impact related to exercise of stock options | - | 0.3 | |||||||
Net cash used for financing activities | (53.8 | ) | (207.7 | ) | |||||
Cash and cash equivalents: | |||||||||
Net change | (21.2 | ) | (51.2 | ) | |||||
Balance at beginning of period | 173.5 | 124.0 | |||||||
Cash and cash equivalents at end of period | $ | 152.3 | $ | 72.8 | |||||
Supplemental cash flow information: | |||||||||
Interest paid, net of amounts capitalized | $ | 66.7 | $ | 30.3 | |||||
Income taxes paid, net | $ | 21.6 | $ | 24.7 | |||||
Non-cash financing and investing activities: | |||||||||
Accruals for capital expenditures | $ | 25.3 | $ | 22.6 | |||||
Long-term liability incurred for purchase of plant assets | $ | - | $ | 18.7 |
See Notes to Condensed Consolidated Financial Statements.
These interim statements are unaudited.
At | At | |||||||
June 30, | December 31, | |||||||
$ in millions | 2012 | 2011 | ||||||
Successor | ||||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 152.3 | $ | 173.5 | ||||
Accounts receivable, net (Note 3) | 208.1 | 219.1 | ||||||
Inventories (Note 3) | 127.0 | 125.8 | ||||||
Taxes applicable to subsequent years | 35.8 | 76.5 | ||||||
Regulatory assets, current (Note 4) | 22.3 | 20.8 | ||||||
Other prepayments and current assets | 35.2 | 36.2 | ||||||
Total current assets | 580.7 | 651.9 | ||||||
Property, plant and equipment: | ||||||||
Property, plant and equipment | 2,525.0 | 2,360.3 | ||||||
Less: Accumulated depreciation and amortization | (121.7 | ) | (7.5 | ) | ||||
2,403.3 | 2,352.8 | |||||||
Construction work in process | 145.2 | 152.3 | ||||||
Total net property, plant and equipment | 2,548.5 | 2,505.1 | ||||||
Other noncurrent assets: | ||||||||
Regulatory assets, non-current (Note 4) | 170.9 | 177.8 | ||||||
Goodwill | 2,568.1 | 2,568.1 | ||||||
Intangible assets, net of amortization | 98.3 | 142.4 | ||||||
Other deferred assets | 42.3 | 51.8 | ||||||
Total other noncurrent assets | 2,879.6 | 2,940.1 | ||||||
Total Assets | $ | 6,008.8 | $ | 6,097.1 |
See Notes to Condensed Consolidated Financial Statements.
These interim statements are unaudited.
DPL INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
At | At | |||||||||||||||
June 30, | December 31, | |||||||||||||||
$ in millions | 2012 | 2011 | ||||||||||||||
Successor | ||||||||||||||||
LIABILITIES AND SHAREHOLDER'S EQUITY | ||||||||||||||||
Current liabilities: | ||||||||||||||||
Current portion - long-term debt (Note 6) | $ | 0.4 | $ | 0.4 | ||||||||||||
Accounts payable | 111.0 | 111.1 | ||||||||||||||
Accrued taxes | 64.9 | 76.3 | ||||||||||||||
Accrued interest | 32.0 | 30.2 | ||||||||||||||
Customer security deposits | 16.5 | 15.9 | ||||||||||||||
Regulatory liabilities, current (Note 4) | - | 0.5 | ||||||||||||||
Dividends payable | 25.0 | - | ||||||||||||||
Insurance and claims costs | 14.2 | 14.2 | ||||||||||||||
Other current liabilities | 60.3 | 61.1 | ||||||||||||||
Total current liabilities | 324.3 | 309.7 | ||||||||||||||
Noncurrent liabilities: | ||||||||||||||||
Long-term debt (Note 6) | 2,619.2 | 2,628.9 | ||||||||||||||
Deferred taxes (Note 7) | 497.9 | 505.7 | ||||||||||||||
Taxes payable | 56.4 | 96.9 | ||||||||||||||
Regulatory liabilities, non-current (Note 4) | 118.2 | 118.6 | ||||||||||||||
Pension, retiree and other benefits | 47.2 | 47.5 | ||||||||||||||
Derivative liability | 42.2 | 36.9 | ||||||||||||||
Unamortized investment tax credit | 3.5 | 3.6 | ||||||||||||||
Other deferred credits | 94.2 | 100.2 | ||||||||||||||
Total noncurrent liabilities | 3,478.8 | 3,538.3 | ||||||||||||||
Redeemable preferred stock of subsidiary | 18.4 | 18.4 | ||||||||||||||
Commitments and contingencies (Note 13) | ||||||||||||||||
Common shareholder's equity: | ||||||||||||||||
Common stock: | Successor | |||||||||||||||
No par value | ||||||||||||||||
June 30, 2012 | December 31, 2011 | |||||||||||||||
Shares authorized | 1,500 | 1,500 | ||||||||||||||
Shares issued | 1 | 1 | ||||||||||||||
Shares outstanding | 1 | 1 | ||||||||||||||
Other paid-in capital | 2,236.6 | 2,237.3 | ||||||||||||||
Accumulated other comprehensive income / (loss) | (6.8 | ) | (0.4 | ) | ||||||||||||
Retained earnings / (deficit) | (42.5 | ) | (6.2 | ) | ||||||||||||
Total common shareholder's equity | 2,187.3 | 2,230.7 | ||||||||||||||
Total Liabilities and Shareholder's Equity | $ | 6,008.8 | $ | 6,097.1 |
See Notes to Condensed Consolidated Financial Statements.
These interim statements are unaudited.
1. Overview and Summary of Significant Accounting Policies
Description of Business
DPL is a diversified regional energy company organized in 1985 under the laws of Ohio. DPL’s two reportable segments are the Utility segment, comprised of its DP&L subsidiary, and the Competitive Retail segment, comprised of its DPLER operations, which include the operations of DPLER’s wholly owned subsidiary MC Squared. Refer to Note 14 for more information relating to these reportable segments.
On November 28, 2011, DPL was acquired by AES in the Merger and DPL became a wholly owned subsidiary of AES. See Note 2.
DP&L is a public utility incorporated in 1911 under the laws of Ohio. DP&L is engaged in the generation, transmission, distribution and sale of electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio. Electricity for DP&L's 24 county service area is primarily generated at eight coal-fired power plants and is distributed to more than 500,000 retail customers. Principal industries served include automotive, food processing, paper, plastic manufacturing and defense.
DP&L's sales reflect the general economic conditions and seasonal weather patterns of the area. DP&L sells any excess energy and capacity into the wholesale market.
DPLER sells competitive retail electric service, under contract, to residential, commercial and industrial customers. DPLER’s operations include those of its wholly owned subsidiary, MC Squared, which was acquired on February 28, 2011. DPLER has approximately 70,000 customers currently located throughout Ohio and Illinois. DPLER does not own any transmission or generation assets, and all of DPLER’s electric energy was purchased from DP&L or PJM to meet its sales obligations. DPLER’s sales reflect the general economic conditions and seasonal weather patterns of the areas it serves.
DPL’s other significant subsidiaries include DPLE, which owns and operates peaking generating facilities from which it makes wholesale sales of electricity and MVIC, our captive insurance company that provides insurance services to us and our subsidiaries. All of DPL’s subsidiaries are wholly owned.
DPL also has a wholly owned business trust, DPL Capital Trust II, formed for the purpose of issuing trust capital securities to investors.
DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators while its generation business is deemed competitive under Ohio law. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are expected to be recovered in future customer rates, and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs.
DPL and its subsidiaries employed 1,493 people as of June 30, 2012, of which 1,446 employees were employed by DP&L. Approximately 53% of all employees are under a collective bargaining agreement which expires on October 31, 2014.
Financial Statement Presentation
DPL’s Condensed Consolidated Financial Statements include the accounts of DPL and its wholly owned subsidiaries except for DPL Capital Trust II which is not consolidated, consistent with the provisions of GAAP. DP&L’s undivided ownership interests in certain coal-fired generating plants are included in the financial statements at amortized cost, which was adjusted to fair value at the Merger date for DPL Inc. Operating revenues and expenses are included on a pro-rata basis in the corresponding lines in the Condensed Consolidated Statement of Operations. See Note 5 for more information.
Certain excise taxes collected from customers have been reclassified out of operating expenses in the 2011 presentation to conform to AES’ presentation of these items. These taxes are presented net within revenue. Certain immaterial amounts from prior periods have been reclassified to conform to the current reporting presentation.
All material intercompany accounts and transactions are eliminated in consolidation.
These financial statements have been prepared in accordance with GAAP for interim financial statements and with the instructions of Form 10-Q and Regulation S-X. Accordingly, certain information and footnote disclosures normally included in the annual financial statements prepared in accordance with GAAP have been omitted from this interim report. Therefore, our interim financial statements in this report should be read along with the annual financial statements included in our Form 10-K for the fiscal year ended December 31, 2011.
In the opinion of our management, the Condensed Consolidated Financial Statements presented in this report contain all adjustments necessary to fairly state our financial condition as of June 30, 2012; our results of operations for the three and six months ended June 30, 2012 and our cash flows for the six months ended June 30, 2012. Unless otherwise noted, all adjustments are normal and recurring in nature. Due to various factors, including but not limited to, seasonal weather variations, the timing of outages of electric generating units, changes in economic conditions involving commodity prices and competition, and other factors, interim results for the three and six months ended June 30, 2012 may not be indicative of our results that will be realized for the full year ending December 31, 2012.
The preparation of financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the revenues and expenses of the periods reported. Actual results could differ from these estimates. Significant items subject to such estimates and judgments include: the carrying value of property, plant and equipment; unbilled revenues; the valuation of derivative instruments; the valuation of insurance and claims liabilities; the valuation of allowances for receivables and deferred income taxes; regulatory assets and liabilities; reserves recorded for income tax exposures; litigation; contingencies; the valuation of AROs; assets and liabilities related to employee benefits; goodwill; and intangibles.
On November 28, 2011, AES completed the Merger with DPL. As a result of the Merger, DPL is an indirectly wholly owned subsidiary of AES. DPL’s basis of accounting incorporates the application of FASC 805, “Business Combinations” (FASC 805) as of the date of the Merger. FASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the Merger date. DPL’s Condensed Consolidated Financial Statements and accompanying footnotes have been segregated to present pre-merger activity as the “Predecessor” Company and post-merger activity as the “Successor” Company. Purchase accounting impacts, including goodwill recognition, have been “pushed down” to DPL, resulting in the assets and liabilities of DPL being recorded at their respective fair values as of November 28, 2011. These adjustments are subject to change as AES finalizes its purchase price allocation during the applicable measurement period.
As a result of the push down accounting, DPL’s Condensed Consolidated Statements of Operations subsequent to the Merger include amortization expense relating to purchase accounting adjustments and depreciation of fixed assets based upon their fair value. Therefore, the DPL financial data prior to the Merger will not generally be comparable to its financial data subsequent to the Merger.
DPL remeasured the carrying amount of all of its assets and liabilities to fair value, which resulted in the recognition of approximately $2,568.1 million of goodwill. FASC 350, “Intangibles – Goodwill and Other,” requires that goodwill be tested for impairment at the reporting unit level at least annually or more frequently if impairment indicators are present. In evaluating the potential impairment of goodwill, we make estimates and assumptions about revenue, operating cash flows, capital expenditures, growth rates and discount rates based on our budgets and long term forecasts, macroeconomic projections, and current market expectations of returns on similar assets. There are inherent uncertainties related to these factors and management’s judgment in applying these factors. Generally, the fair value of a reporting unit is determined using a discounted cash flow valuation model. We could be required to evaluate the potential impairment of goodwill outside of the required annual assessment process if we experience situations, including but not limited to: deterioration in general economic conditions; changes to our operating or regulatory environment; increased competitive environment; increase in fuel costs particularly when we are unable to pass its effect to customers; negative or declining cash flows; loss of a key contract or customer, particularly when we are unable to replace it on equally favorable terms; or adverse actions or assessments by a regulator. These types of events and the resulting analyses could result in goodwill impairment expense, which could substantially affect our results of operations for those periods.
As part of the purchase accounting, values were assigned to various intangible assets, including customer relationships, customer contracts and the value of our ESP.
Sale of Receivables
In the first quarter of 2012, DPLER began selling receivables from DPLER customers in Duke Energy’s territory to Duke Energy. These sales are at face value for cash at the billed amounts for DPLER customers’ use of energy. There is no recourse or any other continuing involvement associated with the sold receivables. Total receivables sold during the three and six months ended June 30, 2012 were $4.0 million and $5.2 million, respectively.
Property, Plant and Equipment
We record our ownership share of our undivided interest in jointly-held plants as an asset in property, plant and equipment. Property, plant and equipment are stated at cost. For regulated transmission and distribution property, cost includes direct labor and material, allocable overhead expenses and an allowance for funds used during construction (AFUDC). AFUDC represents the cost of borrowed funds and equity used to finance regulated construction projects. For non-regulated property, cost also includes capitalized interest. Capitalization of AFUDC and interest ceases at either project completion or at the date specified by regulators. AFUDC and capitalized interest was $1.2 million and $1.1 million during the three months and $2.6 million and $2.2 million during the six months ended June 30, 2012 and 2011, respectively.
For unregulated generation property, cost includes direct labor and material, allocable overhead expenses and interest capitalized during construction using the provisions of GAAP relating to the accounting for capitalized interest.
For substantially all depreciable property, when a unit of property is retired, the original cost of that property less any salvage value is charged to Accumulated depreciation and amortization.
Property is evaluated for impairment when events or changes in circumstances indicate that its carrying amount may not be recoverable.
Intangibles
Intangibles include emission allowances, renewable energy credits, customer relationships, customer contracts and the value of our ESP. Emission allowances are carried on a first-in, first-out (FIFO) basis for purchased emission allowances. In addition, we recorded emission allowances at their fair value as of the Merger date. Net gains or losses on the sale of excess emission allowances, representing the difference between the sales proceeds and the cost of emission allowances, are recorded as a component of our fuel costs and are reflected in Operating income when realized. During the six months ended June 30, 2012 and 2011, DPL had no gains for the sale of emission allowances. Beginning in January 2010, part of the gains on emission allowances were used to reduce the overall fuel rider charged to our SSO retail customers.
Customer relationships recognized as part of the purchase accounting associated with the Merger are amortized over ten to seventeen years and customer contracts are amortized over the average length of the contracts. The ESP is amortized over one year on a straight-line basis. Emission allowances are amortized as they are used in our operations on a FIFO basis. Renewable energy credits are amortized as they are used or retired.
Prior to the Merger date, emission allowances and renewable energy credits were carried as inventory. Emission allowances and renewable energy credits are now carried as intangibles in accordance with AES’ policy. The amounts for 2011 have been reclassified to reflect this change in presentation.
Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities
DPL collects certain excise taxes levied by state or local governments from its customers. Prior to the Merger date, certain excise and other taxes were recorded gross. Effective on the Merger date, these taxes are accounted for on a net basis and recorded as a reduction in revenues for presentation in accordance with AES policy. The amounts for the three months ended June 30, 2012 and 2011 were $11.9 million and $11.6 million, respectively. The amounts for the six months ended June 30, 2012 and 2011 were $24.8 million and $25.7 million, respectively. The 2011 amounts were reclassified to conform to this presentation.
Share-Based Compensation
We measure the cost of employee services received and paid with equity instruments based on the fair-value of such equity instrument on the grant date. This cost is recognized in results of operations over the period that employees are required to provide service. Liability awards are initially recorded based on the fair-value of equity instruments and are to be re-measured for the change in stock price at each subsequent reporting date until the liability is ultimately settled. The fair-value for employee share options and other similar instruments at the grant date are estimated using option-pricing models and any excess tax benefits are recognized as an addition to paid-in capital. The reduction in income taxes payable from the excess tax benefits is presented in the Condensed Consolidated Statements of Cash Flows within Cash flows from financing activities. As a result of the Merger (see Note 2), vesting of all DPL share-based awards was accelerated as of the Merger date, and none are in existence at June 30, 2012.
Recently Issued Accounting Standards
Offsetting Assets and Liabilities
In December 2011, the FASB issued ASU 2011-11 “Disclosures about Offsetting Assets and Liabilities” (ASU 2011-11) effective for interim and annual reporting periods beginning on or after January 1, 2013. We expect to adopt this ASU on January 1, 2013. This standard updates FASC 210, “Balance Sheet.” ASU 2011-11 updates the disclosures for financial instruments and derivatives to provide more transparent information around the offsetting of assets and liabilities. Entities are required to disclose both gross and net information about both instruments and transactions eligible for offset in the statement of financial position and/or subject to an agreement similar to a master netting agreement. We do not expect these new rules to have a material impact on our overall results of operations, financial position or cash flows.
Recently Adopted Accounting Standards
Fair Value Disclosures
In May 2011, the FASB issued ASU 2011-04 “Fair Value Measurements” (ASU 2011-04) effective for interim and annual reporting periods beginning after December 15, 2011. We adopted this ASU on January 1, 2012. This standard updates FASC 820, “Fair Value Measurements.” ASU 2011-04 essentially converges US GAAP guidance on fair value with the IFRS guidance. The ASU requires more disclosures around Level 3 inputs. It also increases reporting for financial instruments disclosed at fair value but not recorded at fair value and provides clarification of blockage factors and other premiums and discounts. These new rules did not have a material effect on our overall results of operations, financial position or cash flows.
Comprehensive Income
In June 2011, the FASB issued ASU 2011-05 “Presentation of Comprehensive Income” (ASU 2011-05) effective for interim and annual reporting periods beginning after December 15, 2011. We adopted this ASU on January 1, 2012. This standard updates FASC 220, “Comprehensive Income.” ASU 2011-05 essentially converges US GAAP guidance on the presentation of comprehensive income with the IFRS guidance. The ASU requires the presentation of comprehensive income in one continuous financial statement or two separate but consecutive statements. Any reclassification adjustments from other comprehensive income to net income are required to be presented on the face of the Statement of Comprehensive Income. These new rules did not have a material effect on our overall results of operations, financial position or cash flows.
Goodwill Impairment
In September 2011, the FASB issued ASU 2011-08 “Testing Goodwill for Impairment” (ASU 2011-08) effective for interim and annual reporting periods beginning after December 15, 2011. We adopted this ASU on January 1, 2012. This standard updates FASC 350, “Intangibles-Goodwill and Other.” ASU 2011-08 allows an entity to first test Goodwill using qualitative factors to determine if it is more likely than not that the fair value of a reporting unit has been impaired; if so, then the two-step impairment test is performed.
2. Business Combination
On November 28, 2011, AES completed its acquisition of DPL. AES paid cash consideration of approximately $3,483.6 million. The allocation of the purchase price was based on the estimated fair value of assets acquired and liabilities assumed. In addition, Dolphin Subsidiary II, Inc. (a wholly owned subsidiary of AES) issued $1,250.0 million of debt, which, as a result of the merger of DPL and Dolphin Subsidiary II, Inc. was assumed by DPL.
The assets acquired and liabilities assumed in the acquisition were originally recorded at provisional amounts based on the preliminary purchase price allocation. We are in the process of monitoring the following additional information that could impact the purchase price allocation within the measurement period, which could be up to one year from the date of acquisition: discount rates; energy price curves, and dispatching assumptions, all of which could affect the value of the generation business property, plant and equipment; assumptions around customer switching and aggregation, which could affect the value of intangible assets; assumptions on the valuation of regulatory assets and liabilities; deferred income taxes; and the determination of reporting units. If materially different from the final amounts, such provisional amounts will be retrospectively adjusted to reflect any new information about facts and circumstances that existed at the acquisition date that, if known, would have affected the measurement of these amounts. Additionally, key input assumptions and their sensitivity to the valuation of assets acquired and liabilities assumed are continuing to be reviewed by management, which may result in requiring additional information related to these key input assumptions.
During the three months ended June 30, 2012, we recognized a decrease of $70.7 million in the provisional value of property, plant and equipment and a related decrease of $37.5 million in the provisionally recognized deferred tax liabilities as a result of refined information associated with certain contractual arrangements, growth and ancillary revenue assumptions. Additionally, we recognized a decrease of $19.1 million related to certain customer contracts of DPLER and other intangibles and a related decrease of $6.7 million in the provisionally recognized deferred tax liabilities due to refined market and contractual information obtained during this quarter. These purchase price adjustments increased the provisionally recognized goodwill by $78.8 million and have been reflected retrospectively as of December 31, 2011 in the accompanying Condensed Consolidated Balance Sheets. The effect on net income for the six months ended June 30, 2012 was $8.7 million. The effect on net income for the period November 28, 2011 through December 31, 2011 was not material.
Estimated fair value of assets acquired and liabilities assumed as of the Merger date are as follows:
$ in millions | Current purchase price allocation | Preliminary purchase price allocation | ||||||
Cash | $ | 116.4 | $ | 116.4 | ||||
Accounts receivable | 277.6 | 277.6 | ||||||
Inventory | 123.7 | 123.7 | ||||||
Other current assets | 41.0 | 41.0 | ||||||
Property, plant and equipment | 2,477.8 | 2,548.5 | ||||||
Intangible assets subject to amortization | 147.2 | 166.3 | ||||||
Intangible assets - indefinite-lived | 5.0 | 5.0 | ||||||
Regulatory assets | 201.7 | 201.1 | ||||||
Other non-current assets | 58.3 | 58.3 | ||||||
Current liabilities | (405.1 | ) | (400.2 | ) | ||||
Debt | (1,255.1 | ) | (1,255.1 | ) | ||||
Deferred taxes | (514.5 | ) | (558.2 | ) | ||||
Regulatory liabilities | (117.0 | ) | (117.0 | ) | ||||
Other non-current liabilities | (223.1 | ) | (194.7 | ) | ||||
Redeemable preferred stock | (18.4 | ) | (18.4 | ) | ||||
Net identifiable assets acquired | 915.5 | 994.3 | ||||||
Goodwill | 2,568.1 | 2,489.3 | ||||||
Net assets acquired | $ | 3,483.6 | $ | 3,483.6 |
3. Supplemental Financial Information
At | At | |||||||
June 30, | December 31, | |||||||
$ in millions | 2012 | 2011 | ||||||
Successor | ||||||||
Accounts receivable, net: | ||||||||
Unbilled revenue | $ | 71.5 | $ | 72.4 | ||||
Customer receivables | 108.2 | 113.2 | ||||||
Amounts due from partners in jointly-owned plants | 20.4 | 29.2 | ||||||
Coal sales | 3.1 | 1.0 | ||||||
Other | 5.9 | 4.4 | ||||||
Provision for uncollectible accounts | (1.0 | ) | (1.1 | ) | ||||
Total accounts receivable, net | $ | 208.1 | $ | 219.1 | ||||
Inventories, at average cost: | ||||||||
Fuel and limestone | $ | 85.0 | $ | 84.2 | ||||
Plant materials and supplies | 40.0 | 39.8 | ||||||
Other | 2.0 | 1.8 | ||||||
Total inventories, at average cost | $ | 127.0 | $ | 125.8 |
Accumulated Other Comprehensive Income (Loss)
AOCI is included on our balance sheets within the Common shareholder’s equity sections. The following table provides the components that constitute the balance sheet amounts in AOCI at June 30, 2012 and December 31, 2011:
At | At | |||||||
June 30, | December 31, | |||||||
$ in millions | 2012 | 2011 | ||||||
Successor | ||||||||
Financial instruments, net of tax | $ | 0.3 | $ | - | ||||
Cash flow hedges, net of tax | (7.1 | ) | (0.5 | ) | ||||
Pension and postretirement benefits, net of tax | - | 0.1 | ||||||
Total | $ | (6.8 | ) | $ | (0.4 | ) |
4. Regulatory Assets and Liabilities
In accordance with GAAP, regulatory assets and liabilities are recorded in the Condensed Consolidated Balance Sheets for our regulated electric transmission and distribution businesses. Regulatory assets are the deferral of costs expected to be recovered in future customer rates and regulatory liabilities represent current recovery of expected future costs or gains probable of being reflected in future rates.
We evaluate our regulatory assets each period and believe recovery of these assets is probable. We have received or requested a return on certain regulatory assets for which we are currently recovering or seeking recovery through rates. We record a return after it has been authorized in an order by a regulator.
Regulatory assets and liabilities are classified as current or non-current based on the term in which recovery is expected.
The following table presents DPL’s regulatory assets and liabilities:
At | At | |||||||||||||||
Type of | Amortization | June 30, | December 31, | |||||||||||||
$ in millions | Recovery (a) | Through | 2012 | 2011 | ||||||||||||
Current Regulatory Assets: | ||||||||||||||||
TCRR, transmission, ancillary and other PJM-related costs | F | Ongoing | $ | 5.4 | $ | 4.7 | ||||||||||
Power plant emission fees | C | Ongoing | 1.4 | 4.8 | ||||||||||||
Fuel and purchased power recovery costs | C | Ongoing | 15.5 | 11.3 | ||||||||||||
Total current regulatory assets | $ | 22.3 | $ | 20.8 | ||||||||||||
Non-current Regulatory Assets: | ||||||||||||||||
Deferred recoverable income taxes | B/C | Ongoing | $ | 22.5 | $ | 24.1 | ||||||||||
Pension and postretirement benefits | C | Ongoing | 88.9 | 92.1 | ||||||||||||
Unamortized loss on reacquired debt | C | Ongoing | 12.4 | 13.0 | ||||||||||||
Regional transmission organization costs | D | 2014 | 3.3 | 4.1 | ||||||||||||
Deferred storm costs - 2008 | D | 18.5 | 17.9 | |||||||||||||
CCEM smart grid and advanced metering infrastructure costs | D | 6.6 | 6.6 | |||||||||||||
CCEM energy efficiency program costs | F | Ongoing | 7.3 | 8.8 | ||||||||||||
Consumer education campaign | D | 3.0 | 3.0 | |||||||||||||
Retail settlement system costs | D | 3.1 | 3.1 | |||||||||||||
Other costs | 5.3 | 5.1 | ||||||||||||||
Total non-current regulatory assets | $ | 170.9 | $ | 177.8 | ||||||||||||
Current Regulatory Liabilities | ||||||||||||||||
Other | C | Ongoing | $ | - | $ | 0.5 | ||||||||||
Total current regulatory liabilities | $ | - | $ | 0.5 | ||||||||||||
Non-current Regulatory Liabilities: | ||||||||||||||||
Estimated costs of removal - regulated property | $ | 112.4 | $ | 112.4 | ||||||||||||
Postretirement benefits | 5.8 | 6.2 | ||||||||||||||
Total non-current regulatory liabilities | $ | 118.2 | $ | 118.6 |
(a) | B – Balance has an offsetting liability resulting in no effect on rate base. |
C – Recovery of incurred costs without a rate of return.
D – Recovery not yet determined, but is probable of occurring in future rate proceedings.
F – Recovery of incurred costs plus rate of return.
Regulatory Assets
TCRR, transmission, ancillary and other PJM-related costs represent the costs related to transmission, ancillary service and other PJM-related charges that have been incurred as a member of PJM. On an annual basis, retail rates are adjusted to true-up costs with recovery in rates.
Power plant emission fees represent costs paid to the State of Ohio since 2002. As part of the fuel factor settlement agreement in November 2011, these costs are being recovered through the fuel factor.
Fuel and purchased power recovery costs represent prudently incurred fuel, purchased power, derivative, emission and other related costs which will be recovered from or returned to customers in the future through the operation of the fuel and purchased power recovery rider. The fuel and purchased power recovery rider fluctuates based on actual costs and recoveries and is modified at the start of each seasonal quarter. DP&L implemented the fuel and purchased power recovery rider on January 1, 2010. As part of the PUCO approval process, an outside auditor is hired to review fuel costs and the fuel procurement process. We received the audit report for 2011 on April 27, 2012. The auditor has recommended that the PUCO consider reducing DP&L’s recovery of fuel costs by approximately $3.3 million from certain transactions. We will have further discussions with interested parties concerning the audit report in the last half of 2012.
Deferred recoverable income taxes represent deferred income tax assets recognized from the normalization of flow through items as the result of tax benefits previously provided to customers. This is the cumulative flow through benefit given to regulated customers that will be collected from them in future years. Since currently existing temporary differences between the financial statements and the related tax basis of assets will reverse in subsequent periods, these deferred recoverable income taxes will decrease over time.
Pension benefits represent the qualifying FASC 715 “Compensation – Retirement Benefits” costs of our regulated operations that for ratemaking purposes are deferred for future recovery. We recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income (OCI), the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. This regulatory asset represents the regulated portion that would otherwise be charged as a loss to OCI.
Unamortized loss on reacquired debt represents losses on long-term debt reacquired or redeemed in prior periods. These costs are being amortized over the lives of the original issues in accordance with FERC and PUCO rules.
Regional transmission organization costs represent costs incurred to join an RTO. The recovery of these costs will be requested in a future FERC rate case. In accordance with FERC precedence, we are amortizing these costs over a 10-year period that began in 2004 when we joined the PJM RTO.
Deferred storm costs – 2008 relate to costs incurred to repair the damage caused by hurricane force winds in September 2008, as well as other major 2008 storms. On January 14, 2009, the PUCO granted DP&L the authority to defer these costs with a return until such time that DP&L seeks recovery in a future rate proceeding.
CCEM smart grid and AMI costs represent costs incurred as a result of studying and developing distribution system upgrades and implementation of AMI. On October 19, 2010, DP&L elected to withdraw its case pertaining to the Smart Grid and AMI programs. The PUCO accepted the withdrawal in an order issued on January 5, 2011. The PUCO also indicated that it expects DP&L to continue to monitor other utilities’ Smart Grid and AMI programs and to explore the potential benefits of investing in Smart Grid and AMI programs and that DP&L will, when appropriate, file new Smart Grid and/or AMI business cases in the future. We plan to file to recover these deferred costs in a future regulatory rate proceeding. Based on past PUCO precedent, we believe these costs are probable of future recovery in rates.
CCEM energy efficiency program costs represent costs incurred to develop and implement various new customer programs addressing energy efficiency. These costs are being recovered through an energy efficiency rider that began July 1, 2009 and is subject to a two-year true-up for any over/under recovery of costs. The two-year true-up was approved by the PUCO and a new rate was set.
Consumer education campaign represents costs for consumer education advertising regarding electric deregulation.
Retail settlement system costs represent costs to implement a retail settlement system that reconciles the energy a CRES supplier delivers to its customers and what its customers actually use. Based on case precedent in other utilities’ cases, the costs are recoverable through a future DP&L rate proceeding.
Other costs primarily include RPM capacity, other PJM and rate case costs and alternative energy costs that are or will be recovered over various periods.
Regulatory Liabilities
Estimated costs of removal – regulated property reflect an estimate of amounts collected in customer rates for costs that are expected to be incurred in the future to remove existing transmission and distribution property from service when the property is retired.
Postretirement benefits represent the qualifying FASC 715 “Compensation – Retirement Benefits” gains related to our regulated operations that, for ratemaking purposes, are probable of being reflected in future rates. We recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of OCI, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. This regulatory liability represents the regulated portion that would otherwise be reflected as a gain to OCI.
5. Ownership of Coal-fired Facilities
DP&L and certain other Ohio utilities have undivided ownership interests in seven coal-fired electric generating facilities and numerous transmission facilities. Certain expenses, primarily fuel costs for the generating units, are allocated to the owners based on their energy usage. The remaining expenses, investments in fuel inventory, plant materials and operating supplies, and capital additions are allocated to the owners in accordance with their respective ownership interests. As of June 30, 2012, DP&L had $71.0 million of construction work in process at such jointly-owned facilities. DP&L’s share of the operating cost of such facilities is included within the corresponding line in the Condensed Consolidated Statements of Results of Operations and DP&L’s share of the investment in the facilities is included within Total net property, plant and equipment in the Condensed Consolidated Balance Sheets. Each joint owner provides their own financing for their share of the operations and capital expenditures of the jointly owned plant.
DP&L’s undivided ownership interest in such facilities as well as our wholly owned coal-fired Hutchings station at June 30, 2012 is as follows:
DP&L Investment | |||||||||||||||||||||
DP&L Share | (adjusted to fair value at Merger date) | ||||||||||||||||||||
SCR and FGD | |||||||||||||||||||||
Equipment | |||||||||||||||||||||
Summer | Construction | Installed | |||||||||||||||||||
Production | Gross Plant | Accumulated | Work in | and in | |||||||||||||||||
Ownership | Capacity | in Service | Depreciation | Process | Service | ||||||||||||||||
(%) | (MW) | ($ in millions) | ($ in millions) | ($ in millions) | (Yes/No) | ||||||||||||||||
Production Units: | |||||||||||||||||||||
Beckjord Unit 6 | 50.0 | 207 | $ | 1 | $ | 1 | $ | - | No | ||||||||||||
Conesville Unit 4 | 16.5 | 129 | 44 | 2 | 7 | Yes | |||||||||||||||
East Bend Station | 31.0 | 186 | 5 | 4 | 7 | Yes | |||||||||||||||
Killen Station | 67.0 | 402 | 313 | 10 | 6 | Yes | |||||||||||||||
Miami Fort Units 7 and 8 | 36.0 | 368 | 219 | 7 | 2 | Yes | |||||||||||||||
Stuart Station | 35.0 | 808 | 203 | 10 | 11 | Yes | |||||||||||||||
Zimmer Station | 28.1 | 365 | 141 | 19 | 38 | Yes | |||||||||||||||
Transmission (at varying percentages) | 35 | 2 | - | ||||||||||||||||||
Total | 2,465 | $ | 961 | $ | 55 | $ | 71 | ||||||||||||||
Wholly-owned production unit: | |||||||||||||||||||||
Hutchings Station | 100.0 | 365 | $ | 1 | $ | - | $ | 1 | No | ||||||||||||
Currently, our coal-fired generation units at Hutchings and Beckjord do not have the SCR and FGD emission-control equipment installed. DP&L owns 100% of the Hutchings station and has a 50% interest in Beckjord Unit 6. On July 15, 2011, Duke Energy, a co-owner at the Beckjord Unit 6 facility, filed their Long-term Forecast Report with the PUCO. The plan indicated that Duke Energy plans to cease production at the Beckjord station, including our jointly owned Unit 6, in December 2014. This was followed by a notification by Duke Energy to PJM, dated February 1, 2012, of a planned April 1, 2015 deactivation of this unit. DP&L does not object to Duke’s decision. Beckjord Unit 6 was valued at zero at the Merger date.
We are considering options for the Hutchings station, but have not yet made a final decision. DP&L has informed PJM that Hutchings Unit 4 has incurred damage to a rotor and will be deactivated and unavailable for service until at least June 1, 2014, if ever. In addition, DP&L has notified PJM that Hutchings Units 1 and 2 will be deactivated by June 1, 2015. The decision to deactivate Units 1 and 2 has been made because these two units are not equipped with the advanced environmental control technologies needed to comply with the MACT standard and the cost of compliance with the MACT standard or conversion to natural gas for these units would likely exceed the expected return. DP&L is still studying the option of converting two or more of Hutchings Units 3-6 to natural gas in order to comply with environmental requirements.
DPL revalued DP&L’s investment in the above plants at the estimated fair value for each plant at the Merger date.
6. Debt Obligations
All debt outstanding at the Merger date was revalued at the estimated fair value.
Long-term debt | At | At | ||||||
June 30, | December 31, | |||||||
$ in millions | 2012 | 2011 | ||||||
Successor | ||||||||
First mortgage bonds maturing in October 2013 - 5.125% | $ | 494.0 | $ | 503.6 | ||||
Pollution control series maturing in January 2028 - 4.70% | 36.1 | 36.1 | ||||||
Pollution control series maturing in January 2034 - 4.80% | 179.6 | 179.6 | ||||||
Pollution control series maturing in September 2036 - 4.80% | 96.2 | 96.2 | ||||||
Pollution control series maturing in November 2040 - | ||||||||
variable rates: 0.04% - 0.26% and 0.06% - 0.32% (a) | 100.0 | 100.0 | ||||||
U.S. Government note maturing in February 2061 - 4.20% | 18.4 | 18.5 | ||||||
924.3 | 934.0 | |||||||
Obligation for capital lease | 0.2 | 0.4 | ||||||
Unamortized debt discount | - | - | ||||||
Total long-term debt at subsidiary | 924.5 | 934.4 | ||||||
Bank Term Loan - variable rates: 2.24% - 2.30% and 1.48% - 4.25% (b) | 425.0 | |||||||
Senior unsecured bonds maturing October 2016 - 6.50% | 450.0 | 450.0 | ||||||
Senior unsecured bonds maturing October 2021 - 7.25% | 800.0 | 800.0 | ||||||
Note to DPL Capital Trust II maturing in September 2031 - 8.125% | 19.7 | 19.5 | ||||||
Total long-term debt | $ | 2,619.2 | $ | 2,628.9 | ||||
Current portion - long-term debt | At | At | ||||||
June 30, | December 31, | |||||||
$ in millions | 2012 | 2011 | ||||||
Successor | ||||||||
U.S. Government note maturing in February 2061 - 4.20% | $ | 0.1 | $ | 0.1 | ||||
Obligation for capital lease | 0.3 | 0.3 | ||||||
Total current portion - long-term debt at subsidiary | $ | 0.4 | $ | 0.4 |
(a) Range of interest rates for the six months ended June 30, 2012 and the twelve months ended December 31, 2011, respectively.
(b) Range of interest rates for the six months ended June 30, 2012 and from the draw-down of the loan in August 2011 through December 31, 2011, respectively.
At June 30, 2012, maturities of long-term debt, including capital lease obligations, are summarized as follows:
$ in millions | DPL | |||
Due within one year | $ | 0.4 | ||
Due within two years | 470.4 | |||
Due within three years | 425.1 | |||
Due within four years | 0.1 | |||
Due within five years | 450.1 | |||
Thereafter | 1,252.8 | |||
2,598.9 | ||||
Unamortized adjustments to market | ||||
value from purchase accounting | 20.7 | |||
Total long-term debt | $ | 2,619.6 |
Premiums or discounts recognized at the Merger date are amortized over the life of the debt using the effective interest method.
On December 4, 2008, the OAQDA issued $100.0 million of collateralized, variable rate Revenue Refunding Bonds Series A and B due November 1, 2040. In turn, DP&L borrowed these funds from the OAQDA and issued corresponding First Mortgage Bonds to support repayment of the funds. The payment of principal and interest on each series of the bonds when due is backed by a standby letter of credit issued by JPMorgan Chase Bank, N.A. This letter of credit facility, which expires in December 2013, is irrevocable and has no subjective acceleration clauses. Fees associated with this letter of credit facility were not material during the three and six months ended June 30, 2012 and 2011.
On April 20, 2010, DP&L entered into a $200.0 million unsecured revolving credit agreement with a syndicated bank group. This agreement is for a three year term expiring on April 20, 2013 and provides DP&L with the ability to increase the size of the facility by an additional $50.0 million. DP&L had no outstanding borrowings under this credit facility at June 30, 2012 and December 31, 2011. Fees associated with this revolving credit facility were not material during the three and six months ended June 30, 2012 and 2011. This facility also contains a $50.0 million letter of credit sublimit. As of June 30, 2012, DP&L had no outstanding letters of credit against the facility.
On February 23, 2011, DPL purchased $122.0 million principal amount of DPL Capital Trust II 8.125% capital securities in a privately negotiated transaction. As part of this transaction, DPL paid a $12.2 million, or 10%, premium. Debt issuance costs and unamortized debt discount totaling $3.1 million were also recognized in February 2011 associated with this transaction.
On March 1, 2011, DP&L completed the purchase of $18.7 million of electric transmission and distribution assets from the federal government that are located at the Wright-Patterson Air Force Base. DP&L financed the acquisition of these assets with a note payable to the federal government that is payable monthly over 50 years and bears interest at 4.2% per annum.
On August 24, 2011, DP&L entered into a $200.0 million unsecured revolving credit agreement with a syndicated bank group. This agreement is for a four year term expiring on August 24, 2015 and provides DP&L with the ability to increase the size of the facility by an additional $50.0 million. DP&L had no outstanding borrowings under this credit facility at June 30, 2012 and December 31, 2011. Fees associated with this revolving credit facility were not material during the three and six months ended June 30, 2012. This facility also contains a $50.0 million letter of credit sublimit. As of June 30, 2012, DP&L had no outstanding letters of credit against the facility.
On August 24, 2011, DPL entered into a $125.0 million unsecured revolving credit agreement with a syndicated bank group. This agreement is for a three year term expiring on August 24, 2014. DPL had no outstanding borrowings under this credit facility at June 30, 2012 and December 31, 2011. Fees associated with this revolving credit facility were not material during the three and six months ended June 30, 2012. This facility may also be used to issue letters of credit up to the $125.0 million limit. As of June 30, 2012, DPL had no outstanding letters of credit against the facility.
On August 24, 2011, DPL entered into a $425.0 million unsecured term loan agreement with a syndicated bank group. This agreement is for a three year term expiring on August 24, 2014. DPL has borrowed the entire $425.0 million available under the facility at June 30, 2012. Fees associated with this term loan were not material during the three and six months ended June 30, 2012.
In connection with the closing of the Merger (see Note 2), DPL assumed $1,250.0 million of debt that Dolphin Subsidiary II, Inc., a subsidiary of AES, issued on October 3, 2011 to partially finance the Merger. The $1,250.0 million was issued in two tranches. The first tranche was $450.0 million of five year senior unsecured notes issued with a 6.50% coupon maturing on October 15, 2016. The second tranche was $800.0 million of ten year senior unsecured notes issued with a 7.25% coupon maturing on October 15, 2021.
Substantially all property, plant and equipment of DP&L is subject to the lien of the mortgage securing DP&L’s First and Refunding Mortgage, dated October 1, 1935, with the Bank of New York Mellon as Trustee.
7. Income Taxes
The following table details the effective tax rates for the three and six months ended June 30, 2012 and 2011.
Three Months Ended | Six Months Ended | |||||||||
June 30, | June 30, | |||||||||
2012 | 2011 | 2012 | 2011 | |||||||
Successor | Predecessor | Successor | Predecessor | |||||||
DPL | 51.0% | 34.0% | 37.4% | 35.3% |
Income tax expenses for the three and six months ended June 30, 2012 and 2011 were calculated using the estimated annual effective income tax rates for 2012 and 2011 and reflect estimated annual effective income tax rates of 29.0% and 33.7%, respectively. Management estimates the annual effective tax rate based upon its forecast of annual pre-tax income. To the extent that actual pre-tax results for the year differ from the forecasts applied to the most recent interim period, the rates estimated could be materially different from the actual effective tax rates.
For the three months ended June 30, 2012, DPL increased income tax expense by $3.7 million as a result of the following discrete tax adjustments: an increase to deferred state income taxes of $3.6 million and an increase in other estimated tax liabilities of $0.1 million.
For the six months ended June 30, 2012, DPL increased income tax expense by $3.9 million as a result of the following discrete tax adjustments: an increase to deferred state income taxes of $3.6 million and an increase in other estimated tax liabilities of $0.3 million.
For the three and six months ended June 30, 2012, the increase in DPL’s effective tax rate compared to the same period in 2011 primarily reflects decreased pre-tax earnings and an increase to deferred state income taxes.
Deferred tax liabilities for DPL decreased by approximately $1.5 million and $7.8 million, respectively, during the three and six months ended June 30, 2012. These decreases were primarily related to purchase accounting adjustments, amortization and depreciation.
The Internal Revenue Service began an examination of our 2008 Federal income tax return during the second quarter of 2010 and has continued through the current quarter. At this time, we do not expect the results of this examination to have a material effect on our financial statements.
8. Pension and Postretirement Benefits
DP&L sponsors a defined benefit pension plan for the vast majority of its employees.
We generally fund pension plan benefits as accrued in accordance with the minimum funding requirements of the Employee Retirement Income Security Act of 1974 (ERISA) and, in addition, make voluntary contributions from time to time. There were no contributions made during the six months ended June 30, 2012. DP&L made a discretionary contribution of $40.0 million to the defined benefit plan during the six months ended June 30, 2011.
The amounts presented in the following tables for pension include both the collective bargaining plan formula, the traditional management plan formula, the cash balance plan formula and the SERP in the aggregate. The amounts presented for postretirement include both health and life insurance.
The net periodic benefit cost / (income) of the pension and postretirement benefit plans for the three months ended June 30, 2012 and 2011 was:
Net Periodic Benefit Cost / (Income) | ||||||||||||||||||
Pension | Postretirement | |||||||||||||||||
Successor | Predecessor | Successor | Predecessor | |||||||||||||||
$ in millions | 2012 | 2011 | 2012 | 2011 | ||||||||||||||
Service cost | $ | 1.6 | $ | 1.5 | $ | - | $ | 0.1 | ||||||||||
Interest cost | 4.3 | 4.3 | 0.1 | 0.2 | ||||||||||||||
Expected return on assets (a) | (5.6 | ) | (6.1 | ) | - | - | ||||||||||||
Amortization of unrecognized: | ||||||||||||||||||
Actuarial (gain) / loss | 1.2 | 2.2 | (0.2 | ) | (0.2 | ) | ||||||||||||
Prior service cost | 0.3 | 0.6 | - | - | ||||||||||||||
Net periodic benefit cost / (income) before adjustments | $ | 1.8 | $ | 2.5 | $ | (0.1 | ) | $ | 0.1 |
(a) | For purposes of calculating the expected return on pension plan assets, under GAAP, the market-related value of assets (MRVA) is used. GAAP requires that the difference between actual plan asset returns and estimated plan asset returns be included in the MRVA equally over a period not to exceed five years. We use a methodology under which we include the difference between actual and estimated asset returns in the MRVA equally over a three year period. The MRVA used in the calculation of expected return on pension plan assets for the 2012 and 2011 net periodic benefit cost was approximately $336 million and $316 million, respectively. |
The net periodic benefit cost / (income) of the pension and postretirement benefit plans for the six months ended June 30, 2012 and 2011 was:
Net Periodic Benefit Cost / (Income) | ||||||||||||||||||
Pension | Postretirement | |||||||||||||||||
Successor | Predecessor | Successor | Predecessor | |||||||||||||||
$ in millions | 2012 | 2011 | 2012 | 2011 | ||||||||||||||
Service cost | $ | 3.1 | $ | 2.9 | $ | 0.1 | $ | 0.1 | ||||||||||
Interest cost | 8.6 | 8.6 | 0.4 | 0.5 | ||||||||||||||
Expected return on assets (a) | (11.3 | ) | (12.2 | ) | (0.1 | ) | (0.1 | ) | ||||||||||
Amortization of unrecognized: | ||||||||||||||||||
Actuarial (gain) / loss | 2.4 | 4.5 | (0.4 | ) | (0.4 | ) | ||||||||||||
Prior service cost | 0.7 | 1.1 | - | - | ||||||||||||||
Net periodic benefit cost / (income) before adjustments | $ | 3.5 | $ | 4.9 | $ | - | $ | 0.1 |
(a) | For purposes of calculating the expected return on pension plan assets, under GAAP, the market-related value of assets (MRVA) is used. GAAP requires that the difference between actual plan asset returns and estimated plan asset returns be included in the MRVA equally over a period not to exceed five years. We use a methodology under which we include the difference between actual and estimated asset returns in the MRVA equally over a three year period. The MRVA used in the calculation of expected return on pension plan assets for the 2012 and 2011 net periodic benefit cost was approximately $336 million and $316 million, respectively. |
Benefit payments, which reflect future service, are expected to be paid as follows:
Estimated Future Benefit Payments and Medicare Part D Reimbursements
$ in millions | Pension | Postretirement | ||||||
2012 | $ | 11.5 | $ | 1.2 | ||||
2013 | 22.7 | 2.3 | ||||||
2014 | 23.2 | 2.2 | ||||||
2015 | 23.8 | 2.0 | ||||||
2016 | 24.0 | 1.9 | ||||||
2017 - 2021 | 124.4 | 7.5 |
9. Fair Value Measurements
The fair values of our financial instruments are based on published sources for pricing when possible. We rely on valuation models only when no other methods exist. The value of our financial instruments represents our best estimates of the fair value, which may not be the value realized in the future. The table below presents the fair value and cost of our non-derivative instruments at June 30, 2012 and December 31, 2011. See also Note 10 of Notes to Condensed Consolidated Financial Statements for the fair values of our derivative instruments.
Successor | |||||||||
At June 30, | At December 31, | ||||||||
2012 | 2011 | ||||||||
$ in millions | Cost | Fair Value | Cost | Fair Value | |||||
Assets | |||||||||
Money Market Funds | $ 0.2 | $ 0.2 | $ 0.2 | $ 0.2 | |||||
Equity Securities | 4.0 | 4.9 | 3.9 | 4.4 | |||||
Debt Securities | 5.0 | 5.5 | 5.0 | 5.5 | |||||
Multi-Strategy Fund | 0.3 | 0.2 | 0.3 | 0.2 | |||||
Total Assets | $ 9.5 | $ 10.8 | $ 9.4 | $ 10.3 | |||||
Liabilities | |||||||||
Debt | $ 2,619.6 | $ 2,744.4 | $ 2,629.3 | $ 2,710.6 |
Debt
The carrying value of DPL’s debt was adjusted to fair value at the Merger date. Unrealized gains or losses are not recognized in the financial statements because debt is presented at the carrying value established at the Merger date. The debt amounts include the current portion payable in the next twelve months and have maturities that range from 2013 to 2061.
Master Trust Assets
DP&L established a Master Trust to hold assets that could be used for the benefit of employees participating in employee benefit plans. These assets are primarily comprised of open-ended mutual funds which are valued using the net asset value per unit. These investments are recorded at fair value within Other deferred assets on the balance sheets and classified as available for sale. Any unrealized gains or losses are recorded in AOCI until the securities are sold.
DPL had $0.5 million ($0.3 million after tax) of unrealized gains and immaterial losses on the Master Trust assets in AOCI at June 30, 2012 and immaterial unrealized gains and losses in AOCI at December 31, 2011.
Due to the liquidation of the DPL Inc. common stock held in the Master Trust, there is sufficient cash to cover the next twelve months of benefits payable to employees covered under the benefit plans. Therefore, no unrealized gains or losses are expected to be transferred to earnings since we will not need to sell any investments in the next twelve months.
Net Asset Value (NAV) per Unit
The following table discloses the fair value and redemption frequency for those assets whose fair value is estimated using the NAV per unit as of June 30, 2012 and December 31, 2011. These assets are part of the Master Trust. Fair values estimated using the NAV per unit are considered Level 2 inputs within the fair value hierarchy, unless they cannot be redeemed at the NAV per unit on the reporting date. Investments that have restrictions on the redemption of the investments are Level 3 inputs. As of June 30, 2012, DPL did not have any investments for sale at a price different from the NAV per unit.
Fair Value Estimated Using Net Asset Value per Unit (Successor) |
$ in millions | Fair Value at June 30, 2012 | Fair Value at December 31, 2011 | Unfunded Commitments | |||||||||
Money Market Fund (a) | $ | 0.2 | $ | 0.2 | $ | - | ||||||
Equity Securities (b) | 4.9 | 4.4 | - | |||||||||
Debt Securities (c) | 5.5 | 5.5 | - | |||||||||
Multi-Strategy Fund (d) | 0.2 | 0.2 | - | |||||||||
Total | $ | 10.8 | $ | 10.3 | $ | - |
(a) This category includes investments in high-quality, short-term securities. Investments in this category can be redeemed immediately at the current net asset value per unit. |
(b) This category includes investments in hedge funds representing an S&P 500 Index and the Morgan Stanley Capital International (MSCI) U.S. Small Cap 1750 Index. Investments in this category can be redeemed immediately at the current net asset value per unit. |
(c) This category includes investments in U.S. Treasury obligations and U.S. investment grade bonds. Investments in this category can be redeemed immediately at the current net asset value per unit. |
(d) This category includes a mix of actively managed funds holding investments in stocks, bonds and short-term investments in a mix of actively managed funds. Investments in this category can be redeemed immediately at the current net asset value per unit. |
Fair Value Hierarchy
Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. These inputs are then categorized as Level 1 (quoted prices in active markets for identical assets or liabilities); Level 2 (observable inputs such as quoted prices for similar assets or liabilities or quoted prices in markets that are not active); or Level 3 (unobservable inputs).
Valuations of assets and liabilities reflect the value of the instrument including the values associated with counterparty risk. We include our own credit risk and our counterparty’s credit risk in our calculation of fair value using global average default rates based on an annual study conducted by a large rating agency.
We did not have any transfers of the fair values of our financial instruments between Level 1 and Level 2 of the fair value hierarchy.
The fair value of assets and liabilities at June 30, 2012 and December 31, 2011 measured on a recurring basis and the respective category within the fair value hierarchy for DPL was determined as follows:
Assets and Liabilities Measured at Fair Value on a Recurring Basis (Successor) | ||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | ||||||||||||||||||||||
$ in millions | Fair Value at June 30, 2012* | Based on Quoted Prices in Active Markets | Other Observable Inputs | Unobservable Inputs | Collateral and Counterparty Netting | Fair Value on Balance Sheet at June 30, 2012 | ||||||||||||||||||
Assets | ||||||||||||||||||||||||
Master Trust Assets | ||||||||||||||||||||||||
Money Market Funds | $ | 0.2 | $ | - | $ | 0.2 | $ | - | $ | - | $ | 0.2 | ||||||||||||
Equity Securities | 4.9 | - | 4.9 | - | - | 4.9 | ||||||||||||||||||
Debt Securities | 5.5 | - | 5.5 | - | - | 5.5 | ||||||||||||||||||
Multi-Strategy Fund | 0.2 | - | 0.2 | - | - | 0.2 | ||||||||||||||||||
Total Master Trust Assets | 10.8 | - | 10.8 | - | - | 10.8 | ||||||||||||||||||
Derivative Assets | ||||||||||||||||||||||||
Heating Oil Futures | 0.3 | 0.3 | - | - | (0.3 | ) | - | |||||||||||||||||
Forward Power Contracts | 18.3 | - | 18.3 | - | (3.3 | ) | 15.0 | |||||||||||||||||
Total Derivative Assets | 18.6 | 0.3 | 18.3 | - | (3.6 | ) | 15.0 | |||||||||||||||||
Total Assets | $ | 29.4 | $ | 0.3 | $ | 29.1 | $ | - | $ | (3.6 | ) | $ | 25.8 | |||||||||||
Liabilities | ||||||||||||||||||||||||
Derivative Liabilities | ||||||||||||||||||||||||
Interest Rate Hedge | $ | (39.5 | ) | $ | - | $ | (39.5 | ) | $ | - | $ | - | $ | (39.5 | ) | |||||||||
FTRs | (0.1 | ) | - | - | (0.1 | ) | - | (0.1 | ) | |||||||||||||||
Forward NYMEX Coal Contracts | (16.5 | ) | - | (16.5 | ) | - | 11.4 | (5.1 | ) | |||||||||||||||
Forward Power Contracts | (16.0 | ) | - | (16.0 | ) | - | 11.5 | (4.5 | ) | |||||||||||||||
Total Derivative Liabilities | (72.1 | ) | - | (72.0 | ) | (0.1 | ) | 22.9 | (49.2 | ) | ||||||||||||||
Long-term Debt | (2,744.4 | ) | - | (2,725.2 | ) | (19.2 | ) | - | (2,744.4 | ) | ||||||||||||||
Total Liabilities | $ | (2,816.5 | ) | $ | - | $ | (2,797.2 | ) | $ | (19.3 | ) | $ | 22.9 | $ | (2,793.6 | ) | ||||||||
*Includes credit valuation adjustments for counterparty risk and our own credit risk. |
Assets and Liabilities Measured at Fair Value on a Recurring Basis (Successor) | ||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | ||||||||||||||||||||||
$ in millions | Fair Value at December 31, 2011* | Based on Quoted Prices in Active Markets | Other Observable Inputs | Unobservable Inputs | Collateral and Counterparty Netting | Fair Value on Balance Sheet at December 31, 2011 | ||||||||||||||||||
Assets | ||||||||||||||||||||||||
Master Trust Assets | ||||||||||||||||||||||||
Money Market Funds | $ | 0.2 | $ | - | $ | 0.2 | $ | - | $ | - | $ | 0.2 | ||||||||||||
Equity Securities | 4.4 | - | 4.4 | - | - | 4.4 | ||||||||||||||||||
Debt Securities | 5.5 | - | 5.5 | - | - | 5.5 | ||||||||||||||||||
Multi-Strategy Fund | 0.2 | - | 0.2 | - | - | 0.2 | ||||||||||||||||||
Total Master Trust Assets | 10.3 | - | 10.3 | - | - | 10.3 | ||||||||||||||||||
Derivative Assets | ||||||||||||||||||||||||
FTRs | 0.1 | - | 0.1 | - | - | 0.1 | ||||||||||||||||||
Heating Oil Futures | 1.8 | 1.8 | - | - | (1.8 | ) | - | |||||||||||||||||
Forward Power Contracts | 17.3 | - | 17.3 | - | (1.0 | ) | 16.3 | |||||||||||||||||
Total Derivative Assets | 19.2 | 1.8 | 17.4 | - | (2.8 | ) | 16.4 | |||||||||||||||||
Total Assets | $ | 29.5 | $ | 1.8 | $ | 27.7 | $ | - | $ | (2.8 | ) | $ | 26.7 | |||||||||||
Liabilities | ||||||||||||||||||||||||
Derivative Liabilities | ||||||||||||||||||||||||
Interest Rate Hedge | $ | (32.5 | ) | $ | - | $ | (32.5 | ) | $ | - | $ | - | $ | (32.5 | ) | |||||||||
Forward NYMEX Coal Contracts | (14.5 | ) | - | (14.5 | ) | - | 10.8 | (3.7 | ) | |||||||||||||||
Forward Power Contracts | (13.3 | ) | - | (13.3 | ) | - | 5.6 | (7.7 | ) | |||||||||||||||
Total Derivative Liabilities | (60.3 | ) | - | (60.3 | ) | - | 16.4 | (43.9 | ) | |||||||||||||||
Total Liabilities | $ | (60.3 | ) | $ | - | $ | (60.3 | ) | $ | - | $ | 16.4 | $ | (43.9 | ) | |||||||||
*Includes credit valuation adjustments for counterparty risk and our own credit risk. |
We use the market approach to value our financial instruments. Level 1 inputs are used for derivative contracts such as heating oil futures. The fair value is determined by reference to quoted market prices and other relevant information generated by market transactions. Level 2 inputs are used to value derivatives such as forward power contracts and forward NYMEX-quality coal contracts (which are traded on the OTC market but which are valued using prices on the NYMEX for similar contracts on the OTC market). Other Level 2 assets include: open-ended mutual funds that are in the Master Trust, which are valued using the end of day NAV per unit; and interest rate hedges, which use observable inputs to populate a pricing model. Financial transmission rights are considered a Level 3 input, beginning April 1, 2012, because the monthly auctions are considered inactive.
Our Level 3 inputs are immaterial to our derivative balances as a whole and as such no further disclosures are presented.
Our debt is fair valued for disclosure purposes only and most of the fair values are determined using quoted market prices in inactive markets. These fair value inputs are considered Level 2 in the fair value hierarchy. Our long-term leases and the WPAFB loan are not publicly traded. Fair value is assumed to equal carrying value. These fair value inputs are considered Level 3 in the fair value hierarchy as there are no observable inputs. Additional Level 3 disclosures were not presented since debt is not recorded at fair value.
Approximately 99% of the inputs to the fair value of our derivative instruments are from quoted market prices.
Non-recurring Fair Value Measurements
We use the cost approach to determine the fair value of our AROs which are estimated by discounting expected cash outflows to their present value at the initial recording of the liability. Cash outflows are based on the approximate future disposal cost as determined by market information, historical information or other management estimates. These inputs to the fair value of the AROs would be considered Level 3 inputs under the fair value hierarchy. Additions to AROs were not material during the six months ended June 30, 2012 and 2011.
Cash Equivalents
DPL had $110.0 million and $125.0 million in money market funds classified as cash and cash equivalents in its Condensed Consolidated Balance Sheets at June 30, 2012 and December 31, 2011, respectively. The money market funds have quoted prices that are generally equivalent to par and are considered Level 2.
10. | Derivative Instruments and Hedging Activities |
In the normal course of business, DPL enters into various financial instruments, including derivative financial instruments. We use derivatives principally to manage the risk of changes in market prices for commodities and interest rate risk associated with our long-term debt. The derivatives that we use to economically hedge these risks are governed by our risk management policies for forward and futures contracts. Our asset and liability derivative positions with the same counterparty are netted on the balance sheets if we have a master netting agreement with the counterparty. We also net any collateral posted or received against the corresponding derivative asset or liability position. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The objective of the hedging program is to mitigate financial risks while ensuring that we have adequate resources to meet our requirements. We monitor and value derivative positions monthly as part of our risk management processes. We use published sources for pricing, when possible, to mark positions to market. All of our derivative instruments are used for risk management purposes and are designated as cash flow hedges or marked to market each reporting period.
At June 30, 2012, DPL had the following outstanding derivative instruments:
Accounting | Purchases | Sales | Net Purchases/ (Sales) | |||||||||||||
Commodity | Treatment | Unit | (in thousands) | (in thousands) | (in thousands) | |||||||||||
FTRs | Mark to Market | MWh | 15.2 | - | 15.2 | |||||||||||
Heating Oil Futures | Mark to Market | Gallons | 630.0 | - | 630.0 | |||||||||||
Forward Power Contracts | Cash Flow Hedge | MWh | 876.0 | (1,595.2 | ) | (719.2 | ) | |||||||||
Forward Power Contracts | Mark to Market | MWh | 1,981.1 | (4,003.1 | ) | (2,022.0 | ) | |||||||||
NYMEX-quality Coal Contracts* | Mark to Market | Tons | 860.3 | - | 860.3 | |||||||||||
Interest Rate Swaps | Cash Flow Hedge | USD | $ | 160,000.0 | $ | - | $ | 160,000.0 |
* | Includes our partners' share for the jointly-owned plants thatDP&L operates. |
At December 31, 2011, DPL had the following outstanding derivative instruments:
Accounting | Purchases | Sales | Net Purchases/ (Sales) | |||||||||||||
Commodity | Treatment | Unit | (in thousands) | (in thousands) | (in thousands) | |||||||||||
FTRs | Mark to Market | MWh | 7.1 | (0.7 | ) | 6.4 | ||||||||||
Heating Oil Futures | Mark to Market | Gallons | 2,772.0 | - | 2,772.0 | |||||||||||
Forward Power Contracts | Cash Flow Hedge | MWh | 886.2 | (341.6 | ) | 544.6 | ||||||||||
Forward Power Contracts | Mark to Market | MWh | 1,769.4 | (1,739.5 | ) | 29.9 | ||||||||||
NYMEX-quality Coal Contracts* | Mark to Market | Tons | 2,015.0 | - | 2,015.0 | |||||||||||
Interest Rate Swaps | Cash Flow Hedge | USD | $ | 160,000.0 | $ | - | $ | 160,000.0 |
* | Includes our partners' share for the jointly-owned plants that DP&L operates. |
Cash Flow Hedges
As part of our risk management processes, we identify the relationships between hedging instruments and hedged items, as well as the risk management objective and strategy for undertaking various hedge transactions. The fair value of cash flow hedges as determined by observable market prices available as of the balance sheet dates and will continue to fluctuate with changes in market prices up to contract expiration. The effective portion of the hedging transaction is recognized in AOCI and transferred to earnings using specific identification of each contract when the forecasted hedged transaction takes place or when the forecasted hedged transaction is probable of not occurring. The ineffective portion of the cash flow hedge is recognized in earnings in the current period. All risk components were taken into account to determine the hedge effectiveness of the cash flow hedges.
We enter into forward power contracts to manage commodity price risk exposure related to our generation of electricity. We do not hedge all commodity price risk. We reclassify gains and losses on forward power contracts from AOCI into earnings in those periods in which the contracts settle.
We also enter into interest rate derivative contracts to manage interest rate exposure related to anticipated borrowings of fixed-rate debt. Our anticipated fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. We do not hedge all interest rate exposure. During 2011, interest rate hedging relationships with a notional amount of $200.0 million settled resulting in DPL making a cash payment of $48.1 million ($31.3 million net of tax). As part of the Merger discussed in Note 2, DPL entered into a $425.0 million unsecured term loan agreement with a syndicated bank group on August 24, 2011, in part, to pay the approximately $297.4 million principal amount of DPL’s 6.875% debt that was due in September 2011. The remainder was drawn for other corporate purposes. This agreement is for a three year term expiring on August 24, 2014. As a result, some of the forecasted transactions originally being hedged are probable of not occurring and therefore approximately $5.1 million ($3.3 million net of tax) has been reclassified to earnings during the period January 1, 2011 through November 27, 2011. Because the interest rate swap had already cash settled as of the Merger date, this hedge had no future value and was not valued as a part of the purchase accounting (See Note 2 for more information). We reclassify gains and losses on interest rate derivative hedges related to debt financings from AOCI into earnings in those periods in which hedged interest payments occur.
The following table provides information for DPL concerning gains or losses recognized in AOCI for the cash flow hedges for the three months ended June 30, 2012 and 2011:
June 30, 2012 | June 30, 2011 | ||||||||||||||||
Successor | Predecessor | ||||||||||||||||
Interest | Interest | ||||||||||||||||
$ in millions (net of tax) | Power | Rate Hedge | Power | Rate Hedge | |||||||||||||
Beginning accumulated derivative gain / (loss) in AOCI | $ | (2.3 | ) | $ | 8.5 | $ | (1.6 | ) | $ | 22.4 | |||||||
Net gains / (losses) associated with current period hedging transactions | (0.2 | ) | (13.2 | ) | (0.5 | ) | (10.8 | ) | |||||||||
Net gains reclassified to earnings | |||||||||||||||||
Interest Expense | - | - | - | 0.7 | |||||||||||||
Revenues | - | - | 0.3 | - | |||||||||||||
Purchased Power | 0.1 | - | 0.3 | - | |||||||||||||
Ending accumulated derivative gain / (loss) in AOCI | $ | (2.4 | ) | $ | (4.7 | ) | $ | (1.5 | ) | $ | 12.3 | ||||||
Net gains / (losses) associated with the ineffective portion of the hedging transaction | |||||||||||||||||
Interest Expense | $ | - | $ | 2.3 | $ | - | $ | (1.3 | ) | ||||||||
Revenues | $ | - | $ | - | $ | - | $ | - | |||||||||
Purchased Power | $ | - | $ | - | $ | - | $ | - | |||||||||
Portion expected to be reclassified to earnings in the next twelve months* | $ | (1.1 | ) | $ | - | $ | - | $ | - | ||||||||
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) | 30 | 14 | - | - |
* | The actual amounts that we reclassify from AOCI to earnings related to power can differ from the estimateabove due to market price changes. |
The following table provides information for DPL concerning gains or losses recognized in AOCI for the cash flow hedges for the six months ended June 30, 2012 and 2011:
June 30, 2012 | June 30, 2011 | ||||||||||||||||
Successor | Predecessor | ||||||||||||||||
Interest | Interest | ||||||||||||||||
$ in millions (net of tax) | Power | Rate Hedge | Power | Rate Hedge | |||||||||||||
Beginning accumulated derivative gain / (loss) in AOCI | $ | 0.3 | $ | (0.8 | ) | $ | (1.8 | ) | $ | 21.4 | |||||||
Net gains / (losses) associated with current period hedging transactions | (1.6 | ) | (4.2 | ) | (0.9 | ) | (9.2 | ) | |||||||||
Net gains reclassified to earnings | |||||||||||||||||
Interest Expense | - | 0.3 | - | 0.1 | |||||||||||||
Revenues | (1.1 | ) | - | 0.5 | - | ||||||||||||
Purchased Power | - | - | 0.7 | - | |||||||||||||
Ending accumulated derivative gain / (loss) in AOCI | $ | (2.4 | ) | $ | (4.7 | ) | $ | (1.5 | ) | $ | 12.3 | ||||||
Net gains / (losses) associated with the ineffective portion of the hedging transaction | |||||||||||||||||
Interest Expense | $ | - | $ | 1.2 | $ | - | $ | (1.3 | ) | ||||||||
Revenues | $ | - | $ | - | $ | - | $ | - | |||||||||
Purchased Power | $ | - | $ | - | $ | - | $ | - | |||||||||
Portion expected to be reclassified to earnings in the next twelve months* | $ | (1.1 | ) | $ | - | $ | - | $ | - | ||||||||
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) | 30 | 14 | - | - |
* | The actual amounts that we reclassify from AOCI to earnings related to power can differ from the estimateabove due to market price changes. |
The following tables show the fair value and balance sheet classification of DPL’s derivative instruments designated as hedging instruments at June 30, 2012 and December 31, 2011:
Fair Values of Derivative Instruments Designated as Hedging Instruments | ||||||||||||||
at June 30, 2012 (Successor) | ||||||||||||||
Balance Sheet Location | Fair Value on | |||||||||||||
$ in millions | Fair Value1 | Netting 2 | Balance Sheet | |||||||||||
Short-term Derivative Positions | ||||||||||||||
Forward Power Contracts in an Asset Position | $ | 1.8 | $ | (1.5 | ) | Other current assets | $ | 0.3 | ||||||
Forward Power Contracts in a Liability Position | (2.9 | ) | 2.4 | Other current liabilities | (0.5 | ) | ||||||||
Total Short-term Cash Flow Hedges | (1.1 | ) | 0.9 | (0.2 | ) | |||||||||
Long-term Derivative Positions | ||||||||||||||
Forward Power Contracts in a Asset Position | 0.5 | (0.5 | ) | Other deferred assets | - | |||||||||
Forward Power Contracts in a Liability Position | (4.6 | ) | 3.1 | Other deferred credits | (1.5 | ) | ||||||||
Interest Rate Hedges in a Liability Position | (39.5 | ) | - | Other deferred credits | (39.5 | ) | ||||||||
Total Long-term Cash Flow Hedges | (43.6 | ) | 2.6 | (41.0 | ) | |||||||||
Total Cash Flow Hedges | $ | (44.7 | ) | $ | 3.5 | $ | (41.2 | ) |
1 | Includes credit valuation adjustment. |
2 | Includes counterparty and collateral netting. |
Fair Values of Derivative Instruments Designated as Hedging Instruments | ||||||||||||||
at December 31, 2011 (Successor) | ||||||||||||||
Balance Sheet Location | Fair Value on | |||||||||||||
$ in millions | Fair Value1 | Netting 2 | Balance Sheet | |||||||||||
Short-term Derivative Positions | ||||||||||||||
Forward Power Contracts in an Asset Position | $ | 1.5 | $ | (0.9 | ) | Other current assets | $ | 0.6 | ||||||
Forward Power Contracts in a Liability Position | (0.2 | ) | - | Other current liabilities | (0.2 | ) | ||||||||
Total Short-term Cash Flow Hedges | 1.3 | (0.9 | ) | 0.4 | ||||||||||
Long-term Derivative Positions | ||||||||||||||
Forward Power Contracts in an Asset Position | 0.1 | (0.1 | ) | Other deferred assets | - | |||||||||
Forward Power Contracts in a Liability Position | (2.6 | ) | 1.7 | Other deferred credits | (0.9 | ) | ||||||||
Interest Rate Hedges in a Liability Position | (32.5 | ) | - | Other deferred credits | (32.5 | ) | ||||||||
Total Long-term Cash Flow Hedges | (35.0 | ) | 1.6 | (33.4 | ) | |||||||||
Total Cash Flow Hedges | $ | (33.7 | ) | $ | 0.7 | $ | (33.0 | ) |
1 | Includes credit valuation adjustment. |
2 | Includes counterparty and collateral netting. |
Mark to Market Accounting
Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for hedge accounting or the normal purchase and sales exceptions under FASC Topic 815. Accordingly, such contracts are recorded at fair value with changes in the fair value charged or credited to the Condensed Consolidated Statements of Results of Operations in the period in which the change occurred. This is commonly referred to as “MTM accounting.” Contracts we enter into as part of our risk management program may be settled financially, by physical delivery or net settled with the counterparty. We currently mark to market Financial Transmission Rights (FTRs), heating oil futures, forward NYMEX-quality coal contracts and certain forward power contracts.
Certain qualifying derivative instruments have been designated as normal purchases or normal sales contracts, as provided under GAAP. Derivative contracts that have been designated as normal purchases or normal sales under GAAP are not subject to MTM accounting treatment and are recognized in the Condensed Consolidated Statements of Results of Operations on an accrual basis.
Regulatory Assets and Liabilities
In accordance with regulatory accounting under GAAP, a cost that is probable of recovery in future rates should be deferred as a regulatory asset and a gain that is probable of being returned to customers should be deferred as a regulatory liability. Portions of the derivative contracts that are marked to market each reporting period and are related to the retail portion of DP&L’s load requirements are included as part of the fuel and purchased power recovery rider approved by the PUCO which began January 1, 2010. Therefore, the Ohio retail customers’ portion of the heating oil futures and the NYMEX-quality coal contracts are deferred as a regulatory asset or liability until the contracts settle. If these unrealized gains and losses are no longer deemed to be probable of recovery through our rates, they will be reclassified into earnings in the period such determination is made.
The following tables show the amount and classification within the Condensed Consolidated Statements of Results of Operations or Condensed Consolidated Balance Sheets of the gains and losses on DPL’s derivatives not designated as hedging instruments for the three and six months ended June 30, 2012 and 2011.
For the three months ended June 30, 2012 (Successor) | ||||||||||||||||||||
$ in millions | NYMEX Coal | Heating Oil | FTRs | Power | Total | |||||||||||||||
Change in unrealized gain / (loss) | $ | 5.7 | $ | (1.3 | ) | $ | (0.2 | ) | $ | 0.9 | $ | 5.1 | ||||||||
Realized gain / (loss) | (9.5 | ) | 0.5 | 0.7 | (2.1 | ) | (10.4 | ) | ||||||||||||
Total | $ | (3.8 | ) | $ | (0.8 | ) | $ | 0.5 | $ | (1.2 | ) | $ | (5.3 | ) | ||||||
Recorded on Balance Sheet: | ||||||||||||||||||||
Partners' share of gain / (loss) | $ | 2.3 | $ | - | $ | - | $ | - | $ | 2.3 | ||||||||||
Regulatory (asset) / liability | 0.8 | (0.6 | ) | - | - | 0.2 | ||||||||||||||
Recorded in Income Statement: gain / (loss) | ||||||||||||||||||||
Revenue | - | - | - | (2.7 | ) | (2.7 | ) | |||||||||||||
Purchased power | - | - | 0.5 | 1.5 | 2.0 | |||||||||||||||
Fuel | (6.9 | ) | (0.3 | ) | - | - | (7.2 | ) | ||||||||||||
O&M | - | 0.1 | - | - | 0.1 | |||||||||||||||
Total | $ | (3.8 | ) | $ | (0.8 | ) | $ | 0.5 | $ | (1.2 | ) | $ | (5.3 | ) |
For the three months ended June 30, 2011 (Predecessor) | ||||||||||||||||||||
$ in millions | NYMEX Coal | Heating Oil | FTRs | Power | Total | |||||||||||||||
Change in unrealized gain / (loss) | $ | (10.2 | ) | $ | (1.4 | ) | $ | 0.1 | $ | (0.1 | ) | $ | (11.6 | ) | ||||||
Realized gain / (loss) | 1.4 | 0.6 | 0.2 | (1.3 | ) | 0.9 | ||||||||||||||
Total | $ | (8.8 | ) | $ | (0.8 | ) | $ | 0.3 | $ | (1.4 | ) | $ | (10.7 | ) | ||||||
Recorded on Balance Sheet: | ||||||||||||||||||||
Partners' share of gain / (loss) | $ | (5.0 | ) | $ | - | $ | - | $ | - | $ | (5.0 | ) | ||||||||
Regulatory (asset) / liability | (2.3 | ) | (0.9 | ) | - | - | (3.2 | ) | ||||||||||||
Recorded in Income Statement: gain / (loss) | ||||||||||||||||||||
Revenue | - | - | - | (3.1 | ) | (3.1 | ) | |||||||||||||
Purchased power | - | - | 0.3 | �� | 1.7 | 2.0 | ||||||||||||||
Fuel | (1.5 | ) | - | - | - | (1.5 | ) | |||||||||||||
O&M | - | 0.1 | - | - | 0.1 | |||||||||||||||
Total | $ | (8.8 | ) | $ | (0.8 | ) | $ | 0.3 | $ | (1.4 | ) | $ | (10.7 | ) |
For the six months ended June 30, 2012 (Successor) | ||||||||||||||||||||
$ in millions | NYMEX Coal | Heating Oil | FTRs | Power | Total | |||||||||||||||
Change in unrealized gain / (loss) | $ | (2.0 | ) | $ | (1.5 | ) | $ | (0.2 | ) | $ | 2.3 | $ | (1.4 | ) | ||||||
Realized gain / (loss) | (14.5 | ) | 1.4 | 0.5 | (4.4 | ) | (17.0 | ) | ||||||||||||
Total | $ | (16.5 | ) | $ | (0.1 | ) | $ | 0.3 | $ | (2.1 | ) | $ | (18.4 | ) | ||||||
Recorded on Balance Sheet: | ||||||||||||||||||||
Partners' share of gain / (loss) | $ | (1.2 | ) | $ | - | $ | - | $ | - | $ | (1.2 | ) | ||||||||
Regulatory (asset) / liability | (0.3 | ) | (0.6 | ) | - | - | (0.9 | ) | ||||||||||||
Recorded in Income Statement: gain / (loss) | ||||||||||||||||||||
Revenue | - | - | - | 0.7 | 0.7 | |||||||||||||||
Purchased power | - | - | 0.3 | (2.8 | ) | (2.5 | ) | |||||||||||||
Fuel | (15.0 | ) | 0.3 | - | - | (14.7 | ) | |||||||||||||
O&M | - | 0.2 | - | - | 0.2 | |||||||||||||||
Total | $ | (16.5 | ) | $ | (0.1 | ) | $ | 0.3 | $ | (2.1 | ) | $ | (18.4 | ) |
For the six months ended June 30, 2011 (Predecessor) | ||||||||||||||||||||
$ in millions | NYMEX Coal | Heating Oil | FTRs | Power | Total | |||||||||||||||
Change in unrealized gain / (loss) | $ | (13.8 | ) | $ | 1.6 | $ | (0.1 | ) | $ | 0.5 | $ | (11.8 | ) | |||||||
Realized gain / (loss) | 3.8 | 0.9 | (0.7 | ) | (2.1 | ) | 1.9 | |||||||||||||
Total | $ | (10.0 | ) | $ | 2.5 | $ | (0.8 | ) | $ | (1.6 | ) | $ | (9.9 | ) | ||||||
Recorded on Balance Sheet: | ||||||||||||||||||||
Partners' share of gain / (loss) | $ | (7.4 | ) | $ | - | $ | - | $ | - | $ | (7.4 | ) | ||||||||
Regulatory (asset) / liability | (2.0 | ) | 0.6 | - | - | (1.4 | ) | |||||||||||||
Recorded in Income Statement: gain / (loss) | ||||||||||||||||||||
Revenue | - | - | - | (4.7 | ) | (4.7 | ) | |||||||||||||
Purchased power | - | - | (0.8 | ) | 3.1 | 2.3 | ||||||||||||||
Fuel | (0.6 | ) | 1.8 | - | - | 1.2 | ||||||||||||||
O&M | - | 0.1 | - | - | 0.1 | |||||||||||||||
Total | $ | (10.0 | ) | $ | 2.5 | $ | (0.8 | ) | $ | (1.6 | ) | $ | (9.9 | ) |
The following table shows the fair value and balance sheet classification of DPL’s derivative instruments not designated as hedging instruments at June 30, 2012:
Fair Values of Derivative Instruments Not Designated as Hedging Instruments | |||||||||||||
at June 30, 2012 (Successor) | |||||||||||||
$ in millions | Fair Value1 | Netting2 | Balance Sheet Location | Fair Value on Balance Sheet | |||||||||
Short-term Derivative Positions | |||||||||||||
FTRs in a Liability Position | $ | (0.1 | ) | $ | - | Other current liabilities | $ | (0.1 | ) | ||||
Forward Power Contracts in an Asset Position | 12.1 | (1.2 | ) | Other prepayments and current assets | 10.9 | ||||||||
Forward Power Contracts in a Liability Position | (6.4 | ) | 5.0 | Other current liabilities | (1.4 | ) | |||||||
NYMEX-quality Coal Forwards in a Liability Position | (12.9 | ) | 7.8 | Other prepayments and current assets | (5.1 | ) | |||||||
Heating Oil Futures in an Asset Position | 0.3 | (0.3 | ) | Other prepayments and current assets | - | ||||||||
Total Short-term Derivative MTM Positions | (7.0 | ) | 11.3 | 4.3 | |||||||||
Long-term Derivative Positions | |||||||||||||
Forward Power Contracts in an Asset Position | 3.9 | (0.1 | ) | Other deferred assets | 3.8 | ||||||||
Forward Power Contracts in a Liability Position | (2.1 | ) | 1.0 | Other deferred credits | (1.1 | ) | |||||||
NYMEX-quality Coal Forwards in a Liability Position | (3.6 | ) | 3.6 | Other deferred assets | - | ||||||||
Total Long-term Derivative MTM Positions | (1.8 | ) | 4.5 | 2.7 | |||||||||
Total MTM Position | $ | (8.8 | ) | $ | 15.8 | $ | 7.0 |
1 | Includes credit valuation adjustment. |
2 | Includes counterparty and collateral netting. |
The following table shows the fair value and balance sheet classification of DPL’s derivative instruments not designated as hedging instruments at December 31, 2011:
Fair Values of Derivative Instruments Not Designated as Hedging Instruments | |||||||||||||
at December 31, 2011 (Successor) | |||||||||||||
$ in millions | Fair Value1 | Netting2 | Balance Sheet Location | Fair Value on Balance Sheet | |||||||||
Short-term Derivative Positions | |||||||||||||
FTRs in an Asset Position | $ | 0.1 | $ | - | Other prepayments and current assets | $ | 0.1 | ||||||
Forward Power Contracts in an Asset Position | 9.9 | - | Other prepayments and current assets | 9.9 | |||||||||
Forward Power Contracts in a Liability Position | (6.5 | ) | 2.6 | Other current liabilities | (3.9 | ) | |||||||
NYMEX-quality Coal Forwards in a Liability Position | (8.3 | ) | 4.6 | Other current liabilities | (3.7 | ) | |||||||
Heating Oil Futures in an Asset Position | 1.8 | (1.8 | ) | Other prepayments and current assets | - | ||||||||
Total Short-term Derivative MTM Positions | (3.0 | ) | 5.4 | 2.4 | |||||||||
Long-term Derivative Positions | |||||||||||||
Forward Power Contracts in an Asset Position | 5.8 | - | Other deferred assets | 5.8 | |||||||||
Forward Power Contracts in a Liability Position | (4.0 | ) | 1.3 | Other deferred credits | (2.7 | ) | |||||||
NYMEX-quality Coal Forwards in a Liability Position | (6.2 | ) | 6.2 | Other deferred credits | - | ||||||||
Total Long-term Derivative MTM Positions | (4.4 | ) | 7.5 | 3.1 | |||||||||
Total MTM Position | $ | (7.4 | ) | $ | 12.9 | $ | 5.5 |
1 | Includes credit valuation adjustment. |
2 | Includes counterparty and collateral netting. |
Certain of our OTC commodity derivative contracts are under master netting agreements that contain provisions that require our debt to maintain an investment grade credit rating from credit rating agencies. Even though our debt has fallen below investment grade, our counterparties to the derivative instruments have not requested immediate payment or demanded immediate and ongoing full overnight collateralization of the MTM loss.
The aggregate fair value of DPL’s commodity derivative instruments that are in a MTM loss position at June 30, 2012 is $32.8 million. This amount is offset by $19.3 million of collateral posted directly with third parties and in a broker margin account which offsets our loss positions on the forward contracts. This liability position is further offset by the asset position of counterparties with master netting agreements of $3.7 million. If our counterparties were to call for collateral, we could have to post collateral for the remaining $9.8 million.
11. | Common Shareholder’s Equity |
Effective on the Merger date, DPL adopted Amended Articles of Incorporation providing for 1,500 authorized common shares, of which one share is outstanding at June 30, 2012.
On October 28, 2009, the DPL Board of Directors approved a Stock Repurchase Program that permitted DPL to use proceeds from the exercise of DPL warrants by warrant holders to repurchase other outstanding DPL warrants or its common stock from time to time in the open market, through private transactions or otherwise. This 2009 Stock Repurchase Program was scheduled to run through June 30, 2012, but was suspended in connection with the Merger with The AES Corporation, discussed in Note 2. In June 2011, 0.7 million warrants were exercised with proceeds of $14.7 million. Since the Stock Repurchase Program was suspended, the proceeds from the June 2011 exercise of warrants were not used to repurchase stock.
As a result of the Merger involving DPL and AES, the outstanding shares of DPL common stock were converted into the right to receive merger consideration of $30.00 per share. When the remaining warrants were exercised in March 2012, DPL paid the warrant holders an amount equal to $9.00 per warrant, which is the difference between the merger consideration of $30.00 per share of DPL common stock and the exercise price of $21.00 per share. This amount was recorded as a $9.0 million liability at the Merger date. At December 31, 2011, DPL had 1.0 million outstanding warrants which were exercised in March 2012. At June 30, 2012, there are no remaining warrants outstanding.
ESOP
In October 1992, our Board of Directors approved the formation of a Company-sponsored ESOP to fund matching contributions to DP&L’s 401(k) retirement savings plan and certain other payments to eligible full-time employees. ESOP shares used to fund matching contributions to DP&L’s 401(k) vested after two, three or five years of service in accordance with the match formula effective for the respective plan match year; other compensation shares awarded vested immediately.
During December 2011, the ESOP Plan was terminated and participant balances were transferred to one of the two DP&L sponsored defined contribution 401(k) plans. On December 5, 2011, the ESOP Trust paid the total outstanding principal and interest of $68.2 million on the loan with DPL, using the merger proceeds from DPL common stock held within the ESOP suspense account.
12. | Earnings per Share |
Basic EPS is based on the weighted-average number of DPL common shares outstanding during the year. Diluted EPS is based on the weighted-average number of DPL common and common-equivalent shares outstanding during the year, except in periods where the inclusion of such common-equivalent shares is anti-dilutive. Excluded from outstanding shares for these weighted-average computations were shares held by DP&L’s Master Trust Plan for deferred compensation and unreleased shares held by DPL’s ESOP.
The common-equivalent shares excluded from the calculation of diluted EPS, because they were anti-dilutive, were not material for the three and six months ended June 30, 2011. Effective with the Merger with AES, DPL is wholly owned by AES and earnings per share information is no longer required.
The following illustrates the reconciliation of the numerators and denominators of the basic and diluted EPS computations:
Successor | Predecessor | ||||||||||||||||||||||||
Three Months Ended June 30, | Three Months Ended June 30, | ||||||||||||||||||||||||
2012 | 2011 | ||||||||||||||||||||||||
$ and shares in millions exceptper share amounts | Per | Per | |||||||||||||||||||||||
Income | Shares | Share | Income | Shares | Share | ||||||||||||||||||||
Basic EPS | N/A | N/A | N/A | $ | 31.7 | 114.2 | $ | 0.28 | |||||||||||||||||
Effect of Dilutive | |||||||||||||||||||||||||
Securities: | |||||||||||||||||||||||||
Warrants | N/A | 0.5 | |||||||||||||||||||||||
Stock options, performance and restricted shares | N/A | 0.2 | |||||||||||||||||||||||
Diluted EPS | N/A | N/A | N/A | $ | 31.7 | 114.9 | $ | 0.28 |
Successor | Predecessor | ||||||||||||||||||||||||
Six Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||||
2012 | 2011 | ||||||||||||||||||||||||
$ and shares in millions except | Per | Per | |||||||||||||||||||||||
per share amounts | Income | Shares | Share | Income | Shares | Share | |||||||||||||||||||
Basic EPS | N/A | N/A | N/A | $ | 75.2 | 114.1 | $ | 0.66 | |||||||||||||||||
Effect of Dilutive | |||||||||||||||||||||||||
Securities: | |||||||||||||||||||||||||
Warrants | N/A | 0.4 | |||||||||||||||||||||||
Stock options, performance and restricted shares | N/A | 0.2 | |||||||||||||||||||||||
Diluted EPS | N/A | N/A | N/A | $ | 75.2 | 114.7 | $ | 0.66 |
13. | Contractual Obligations, Commercial Commitments and Contingencies |
DPL Inc. – Guarantees
In the normal course of business, DPL enters into various agreements with its wholly owned subsidiaries, DPLE and DPLER and its wholly owned subsidiary, MC Squared, providing financial or performance assurance to third parties. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to these subsidiaries on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish these subsidiaries’ intended commercial purposes.
At June 30, 2012, DPL had $26.4 million of guarantees to third parties for future financial or performance assurance under such agreements, including $26.1 million of guarantees, on behalf of DPLE and DPLER and $0.3 million of guarantees on behalf of MC Squared. The guarantee arrangements entered into by DPL with these third parties cover select present and future obligations of DPLE, DPLER and MC Squared to such beneficiaries and are terminable by DPL upon written notice within a certain time to the beneficiaries. The carrying amount of obligations for commercial transactions covered by these guarantees and recorded in our Condensed Consolidated Balance Sheets was $1.0 million at June 30, 2012.
To date, DPL has not incurred any losses related to the guarantees of DPLE’s, DPLER’s and MC Squared’s obligations and we believe it is remote that DPL would be required to perform or incur any losses in the future associated with any of the above guarantees of DPLE’s, DPLER’s and MC Squared’s obligations.
Equity Ownership Interest
DP&L owns a 4.9% equity ownership interest in an electric generation company which is recorded using the cost method of accounting under GAAP. As of June 30, 2012, DP&L could be responsible for the repayment of 4.9%, or $69.2 million, of a $1,411.4 million debt obligation that features maturities from 2013 to 2040. This would only happen if this electric generation company defaulted on its debt payments. As of June 30, 2012, we have no knowledge of such a default.
Commercial Commitments and Contractual Obligations
There have been no material changes, outside the ordinary course of business, to our commercial commitments and to the information disclosed in the contractual obligations table in our Form 10-K for the fiscal year ended December 31, 2011.
Contingencies
In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in our Condensed Consolidated Financial Statements, as prescribed by GAAP, are adequate in light of the probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims, tax examinations and other matters discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our Condensed Consolidated Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided as of June 30, 2012, cannot be reasonably determined.
Environmental Matters
DPL, DP&L and our subsidiaries’ facilities and operations are subject to a wide range of federal, state and local environmental regulations and laws. As well as imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. In the normal course of business, we have investigatory and remedial activities underway at these facilities to comply, or to determine compliance, with such regulations. We record liabilities for losses that are probable of occurring and can be reasonably estimated in accordance with the provisions of GAAP. We have estimated liabilities of approximately $4.3 million for environmental matters. We evaluate the potential liability related to probable losses quarterly and may revise our estimates. Such revisions in the estimates of the potential liabilities could have a material adverse effect on our results of operations, financial condition or cash flows.
We have several pending environmental matters associated with our power plants. Some of these matters could have material adverse impacts on our business and on the operation of the power plants; especially the plants that do not have SCR and FGD equipment installed to further control certain emissions. Currently, Hutchings and Beckjord are our only coal-fired power plants that do not have this equipment installed. DP&L owns 100% of the Hutchings station and a 50% interest in Beckjord Unit 6.
On July 15, 2011, Duke Energy, a co-owner at the Beckjord Unit 6 facility, filed their Long-term Forecast Report with the PUCO. The plan indicated that Duke Energy plans to cease production at the Beckjord Station, including our jointly owned Unit 6, in December 2014. This was followed by a notification by Duke Energy to PJM, dated February 1, 2012, of a planned April 1, 2015 deactivation of this unit. Beckjord Unit 6 was valued at zero at the Merger date.
We are considering options for the Hutchings station, but have not yet made a final decision. DP&L has informed PJM that Hutchings Unit 4 has incurred damage to a rotor and will be deactivated and unavailable for service until at least June 1, 2014, if ever. In addition, DP&L has notified PJM that Hutchings Units 1 and 2 will be deactivated by June 1, 2015.
DPL revalued DP&L’s investment in the above plants at the estimated fair value for each plant at the Merger date.
Environmental Matters Related to Air Quality
Clean Air Act Compliance
In 1990, the federal government amended the CAA to further regulate air pollution. Under the CAA, the USEPA sets limits on, among other things, how much of certain designated pollutants can be in the ambient air anywhere in the United States. The CAA allows individual states to have stronger pollution controls than those set under the CAA, but states are not allowed to have weaker pollution controls than those set for the whole country. The CAA has a material effect on our operations and such effects are detailed below with respect to certain programs under the CAA.
Cross-State Air Pollution Rule
The Clean Air Interstate Rule (CAIR) final rules were published on May 12, 2005. CAIR created an interstate trading program for annual NOx emission allowances and made modifications to an existing trading program for SO2. Appeals brought by various parties resulted in a decision by the U.S. Court of Appeals for the District of Columbia Circuit on July 11, 2008 to vacate CAIR and its associated Federal Implementation Plan (FIP). On December 23, 2008, the U.S. Court of Appeals issued an order on reconsideration that permits CAIR to remain in effect until the USEPA issues new regulations that would conform to the CAA requirements and the Court’s July 2008 decision.
In an attempt to conform to the Court’s decision, on July 6, 2010, the USEPA proposed the Clean Air Transport Rule (CATR). CATR was finalized as the Cross-State Air Pollution Rule (CSAPR) on July 6, 2011, but subsequent litigation has resulted in CSAPR’s implementation being delayed indefinitely. CSAPR creates four separate trading programs: two SO2 areas (Group 1 and Group 2); and two NOx reduction requirements (annual and ozone season). Group 1 states (16 states including Ohio) will have to meet a 2012 cap and additional reductions in 2014. Group 2 states (7 states) will only have to meet the 2012 cap. We do not believe the rule will have a material effect on our operations in 2012. The Ohio EPA has a State Implementation Plan (SIP) that incorporates the CAIR program requirements, which remain in effect pending judicial review of CSAPR. If CSAPR becomes effective, the USEPA is expected to institute a FIP in lieu of state SIPs and allow for the states to develop SIPs for approval as early as 2013. DP&L is unable to estimate the effect of the new requirements; however, CSAPR could have a material adverse effect on our operations.
Mercury and Other Hazardous Air Pollutants
On May 3, 2011, the USEPA published proposed Maximum Achievable Control Technology (MACT) standards for coal- and oil-fired electric generating units. The standards include new requirements for emissions of mercury and a number of other heavy metals. The USEPA Administrator signed the final rule, now called MATS (Mercury and Air Toxics Standards), on December 16, 2011, and the rule was published in the Federal Register on February 16, 2012. Affected electric generating units (EGUs) will have to come into compliance with the new requirements by April 16, 2015, but may be granted an additional year contingent on Ohio EPA approval. DP&L is evaluating the costs that may be incurred to comply with the new requirement; however, MATS could have a material adverse effect on our operations and result in material compliance costs.
On April 29, 2010, the USEPA issued a proposed rule that would reduce emissions of toxic air pollutants from new and existing industrial, commercial and institutional boilers, and process heaters at major and area source facilities. The final rule was published in the Federal Register on March 21, 2011. This regulation affects seven auxiliary boilers used for start-up purposes at DP&L’s generation facilities. The regulations contain emissions limitations, operating limitations and other requirements. In December 2011, the USEPA proposed additional changes to this rule and solicited comments. Compliance costs are not expected to be material to DP&L’s operations.
On May 3, 2010, the USEPA finalized the “National Emissions Standards for Hazardous Air Pollutants” for compression ignition (CI) reciprocating internal combustion engines (RICE). The units affected at DP&L are 18 diesel electric generating engines and eight emergency “black start” engines. The existing CI RICE units must comply by May 3, 2013. The regulations contain emissions limitations, operating limitations and other requirements. Compliance costs for DP&L’s operations are not expected to be material.
Carbon and Other Greenhouse Gas Emissions
In response to a U.S. Supreme Court decision that the USEPA has the authority to regulate CO2 emissions from motor vehicles, the USEPA made a finding that CO2 and certain other GHGs are pollutants under the CAA. Subsequently, under the CAA, USEPA determined that CO2 and other GHGs from motor vehicles threaten the health and welfare of future generations by contributing to climate change. This finding became effective in January 2010. On June 26, 2012, the D.C. Circuit Court upheld this finding and other GHG regulations following challenges from industry and state opponents. On April 1, 2010, USEPA signed the “Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards” rule. Under USEPA’s view, this is the final action that renders CO2 and other GHGs “regulated air pollutants” under the CAA.
Under USEPA regulations finalized in May 2010 (referred to as the “Tailoring Rule”), the USEPA began regulating GHG emissions from certain stationary sources in January 2011. The Tailoring Rule sets forth criteria for determining which facilities are required to obtain permits for their GHG emissions pursuant to the CAA Prevention of Significant Deterioration and Title V operating permit programs. Under the Tailoring Rule, permitting requirements are being phased in through successive steps that may expand the scope of covered sources over time. The USEPA has issued guidance on what the best available control technology entails for the control of GHGs and individual states are required to determine what controls are required for facilities on a case-by-case basis. The ultimate impact of the Tailoring Rule to DP&L cannot be determined at this time, but the cost of compliance could be material.
On April 13, 2012, the USEPA published its proposed GHG standards for new electric generating units (EGUs) under CAA subsection 111(b), which would require certain new EGUs to meet a standard of 1,000 pounds of CO2 per megawatt-hour, a standard based on the emissions limitations achievable through natural gas combined cycle generation. The proposal anticipates that affected coal-fired units would need to install carbon capture and storage or other expensive CO2 emission control technology to meet the standard. Furthermore, the USEPA may propose and promulgate guidelines for states to address GHG standards for existing EGUs under CAA subsection 111(d). These latter rules may focus on energy efficiency improvements at power plants. We cannot predict the effect of these standards, if any, on DP&L’s operations.
Approximately 98% of the energy we produce is generated by coal. DP&L’s share of CO2 emissions at generating stations we own and co-own is approximately 16 million tons annually. Further GHG legislation or regulation finalized at a future date could have a significant effect on DP&L’s operations and costs, which could adversely affect our net income, cash flows and financial condition. However, due to the uncertainty associated with such legislation or regulation, we cannot predict the final outcome or the financial impact that such legislation or regulation may have on DP&L.
On September 22, 2009, the USEPA issued a final rule for mandatory reporting of GHGs from large sources that emit 25,000 metric tons per year or more of GHGs, including EGUs. DP&L has submitted to USEPA GHG emission reports for 2012 and 2011. While this reporting rule will guide development of policies and programs to reduce emissions, DP&L does not anticipate that the reporting rule will itself result in any significant cost or other effect on current operations.
Litigation, Notices of Violation and Other Matters Related to Air Quality
Litigation Involving Co-Owned Plants
On June 20, 2011, the U.S. Supreme Court ruled that the USEPA’s regulation of GHGs under the CAA displaced any right that plaintiffs may have had to seek similar regulation through federal common law litigation in the court system. Although we are not named as a party to these lawsuits, DP&L is a co-owner of coal-fired plants with Duke Energy and AEP (or their subsidiaries) that could have been affected by the outcome of these lawsuits or similar suits that may have been filed against other electric power companies, including DP&L. Because the issue was not squarely before it, the U.S. Supreme Court did not rule against the portion of plaintiffs’ original suits that sought relief under state law.
As a result of a 2008 consent decree entered into with the Sierra Club and approved by the U.S. District Court for the Southern District of Ohio, DP&L and the other owners of the J.M. Stuart generating station are subject to certain specified emission targets related to NOx, SO2 and particulate matter. The consent decree also includes commitments for energy efficiency and renewable energy activities. An amendment to the consent decree was entered into and approved in 2010 to clarify how emissions would be computed during malfunctions. Continued compliance with the consent decree, as amended, is not expected to have a material effect on DP&L’s results of operations, financial condition or cash flows in the future.
Notices of Violation Involving Co-Owned Plants
In November 1999, the USEPA filed civil complaints and NOVs against operators and owners of certain generation facilities for alleged violations of the CAA. Generation units operated by Duke Energy (Beckjord Unit 6) and CSP (Conesville Unit 4) and co-owned by DP&L were referenced in these actions. Although DP&L was not identified in the NOVs, civil complaints or state actions, the results of such proceedings could materially affect DP&L’s co-owned plants.
In June 2000, the USEPA issued an NOV to the DP&L-operated J.M. Stuart generating station (co-owned by DP&L, Duke Energy, and CSP) for alleged violations of the CAA. The NOV contained allegations that Stuart station engaged in projects between 1978 and 2000 without New Source Review and Prevention of Significant Deterioration permits that resulted in significant increases in particulate matter, SO2, and NOx. These allegations are consistent with NOVs and complaints that the USEPA had brought against numerous other coal-fired utilities in the Midwest. The NOV indicated the USEPA may: (1) issue an order requiring compliance with the requirements of the Ohio SIP; or (2) bring a civil action seeking injunctive relief and civil penalties of up to $27,500 per day for each violation. To date, neither action has been taken. DP&L cannot predict the outcome of this matter.
In December 2007, the Ohio EPA issued an NOV to the DP&L-operated Killen generating station (co-owned by DP&L and Duke Energy) for alleged violations of the CAA. The NOV alleged deficiencies in the continuous monitoring of opacity. We submitted a compliance plan to the Ohio EPA on December 19, 2007. To date, no further actions have been taken by the Ohio EPA.
On March 13, 2008, Duke Energy, the operator of the Zimmer generating station, received an NOV and a Finding of Violation (FOV) from the USEPA alleging violations of the CAA, the Ohio State Implementation Program (SIP) and permits for the station in areas including SO2, opacity and increased heat input. A second NOV and FOV with similar allegations was issued on November 4, 2010. Also in 2010, USEPA issued an NOV to Zimmer for excess emissions. DP&L is a co-owner of the Zimmer generating station and could be affected by the eventual resolution of these matters. Duke Energy is expected to act on behalf of itself and the co-owners with respect to these matters. DP&L is unable to predict the outcome of these matters.
Notices of Violation Involving Wholly Owned Plants
In 2007, the Ohio EPA and the USEPA issued NOVs to DP&L for alleged violations of the CAA at the Hutchings station. The NOVs’ alleged deficiencies relate to stack opacity and particulate emissions. Discussions are under way with the USEPA, the U.S. Department of Justice and Ohio EPA. On November 18, 2009, the USEPA issued an NOV to DP&L for alleged NSR violations of the CAA at the Hutchings station relating to capital projects performed in 2001 involving Unit 3 and Unit 6. DP&L does not believe that the projects described in the NOV were modifications subject to NSR. DP&L is engaged in discussions with the USEPA and the U.S. Department of Justice to resolve these matters, but DP&L is unable to determine the timing, costs or method by which these issues may be resolved. The Ohio EPA is kept apprised of these discussions.
Environmental Matters Related to Water Quality, Waste Disposal and Ash Ponds
Clean Water Act – Regulation of Water Intake
On July 9, 2004, the USEPA issued final rules pursuant to the Clean Water Act governing existing facilities that have cooling water intake structures. The rules require an assessment of impingement and/or entrainment of organisms as a result of cooling water withdrawal. A number of parties appealed the rules. In April 2009, the U.S. Supreme Court ruled that the USEPA did have the authority to compare costs with benefits in determining best technology available. The USEPA released new proposed regulations on March 28, 2011, published in the Federal Register on April 20, 2011. We submitted comments to the proposed regulations on August 17, 2011. It is anticipated that the final rules will be promulgated in mid-2013. We do not yet know the effect these proposed rules will have on our operations.
Clean Water Act – Regulation of Water Discharge
In December 2006, we submitted an application for the renewal of the Stuart station NPDES Permit that was due to expire on June 30, 2007. In July 2007, we received a draft permit proposing to continue our authority to discharge water from the station into the Ohio River. On February 5, 2008, we received a letter from the Ohio EPA indicating that they intended to impose a compliance schedule as part of the final Permit, that requires us to implement one of two diffuser options for the discharge of water from the station into the Ohio River as identified in a thermal discharge study completed during the previous permit term. Subsequently, DP&L and the Ohio EPA reached an agreement to allow DP&L to restrict public access to the water discharge area as an alternative to installing one of the diffuser options. Ohio EPA issued a revised draft permit that was received on November 12, 2008. In December 2008, the USEPA requested that the Ohio EPA provide additional information regarding the thermal discharge in the draft permit. In June 2009, DP&L provided information to the USEPA in response to their request to the Ohio EPA. In September 2010, the USEPA formally objected to a revised permit provided by Ohio EPA due to questions regarding the basis for the alternate thermal limitation. In December 2010, DP&L requested a public hearing on the objection, which was held on March 23, 2011. We participated in and presented our position on the issue at the hearing and in written comments submitted on April 28, 2011. In a letter to the Ohio EPA dated September 28, 2011, the USEPA reaffirmed its objection to the revised permit as previously drafted by the Ohio EPA. This reaffirmation stipulated that if the Ohio EPA does not re-draft the permit to address the USEPA’s objection, then the authority for issuing the permit will pass to the USEPA. The Ohio EPA issued another draft permit in December 2011 and a public hearing was held on February 2, 2012. The draft permit would require DP&L, over the 54 months following issuance of a final permit, to take undefined actions to lower the temperature of its discharged water to a level unachievable by the station under its current design or alternatively make other significant modifications to the cooling water system. DP&L submitted comments to the draft permit and is considering legal options. On May 17, 2012, we met with Ohio EPA to discuss this matter. It is not known what additional actions the agency might take. Depending on the outcome of the process, the effects could be material on DP&L’s operations.
In September 2009, the USEPA announced that it will be revising technology-based regulations governing water discharges from steam electric generating facilities. The rulemaking included the collection of information via an industry-wide questionnaire as well as targeted water sampling efforts at selected facilities. It is anticipated that the USEPA will release a proposed rule by November 2012 with a final regulation in place by early 2014. At present, DP&L is unable to predict the impact this rulemaking will have on its operations.
In April 2012, DP&L received an NOV related to the construction of the Carter Hollow landfill at the J.M. Stuart station. The NOV indicated that construction activities caused sediment to flow into downstream creeks. In addition, the U.S. Army Corps of Engineers issued a Cease and Desist order followed by a notice suspending the previously issued Corps permit authorizing work associated with the landfill. USEPA has indicated that they may take additional enforcement action. DP&L has installed sedimentation ponds as part of the runoff control measures to address this issue and is working with the various agencies to resolve their concerns. This may affect the landfill’s construction schedule and delay its operational date. DP&L has accrued an immaterial amount for anticipated penalties related to this issue.
Regulation of Waste Disposal
In September 2002, DP&L and other parties received a special notice that the USEPA considers us to be a PRP for the clean-up of hazardous substances at the South Dayton Dump landfill site. In August 2005, DP&L and other parties received a general notice regarding the performance of a Remedial Investigation and Feasibility Study (RI/FS) under a Superfund Alternative Approach. In October 2005, DP&L received a special notice letter inviting it to enter into negotiations with the USEPA to conduct the RI/FS. No recent activity has occurred with respect to that notice or PRP status. However, on August 25, 2009, the USEPA issued an Administrative Order requiring that access to DP&L’s service center building site, which is across the street from the landfill site, be given to the USEPA and the existing PRP group to help determine the extent of the landfill site’s contamination as well as to assess whether certain chemicals used at the service center building site might have migrated through groundwater to the landfill site. DP&L granted such access and drilling of soil borings and installation of monitoring wells occurred in late 2009 and early 2010. On May 24, 2010, three members of the existing PRP group, Hobart Corporation, Kelsey-Hayes Company and NCR Corporation, filed a civil complaint in the United States District Court for the Southern District of Ohio against DP&L and numerous other defendants alleging that DP&L and the other defendants contributed to the contamination at the South Dayton Dump landfill site and seeking reimbursement of the PRP group’s costs associated with the investigation and remediation of the site. On February 10, 2011, the Court dismissed claims against DP&L that related to allegations that chemicals used by DP&L at its service center contributed to the landfill site’s contamination. The Court, however, did not dismiss claims alleging financial responsibility for remediation costs based on hazardous substances from DP&L that were allegedly directly delivered by truck to the landfill. Discovery, including depositions of past and present DP&L employees, is ongoing. In June 2012, DP&L filed a motion for summary judgment on grounds that the remaining claims for contribution are barred by a statute of limitations. The plaintiffs opposed that motion and, additionally, have filed a motion seeking Court leave to amend their complaint to add more than 20 new defendants to the case and to recharacterize and re-allege claims against DP&L that the Court dismissed in its February 10, 2011 order. While DP&L is unable to predict the outcome of these matters, if DP&L were required to contribute to the clean-up of the site, it could have a material adverse effect on its operations.
In December 2003, DP&L and other parties received a special notice that the USEPA considers us to be a PRP for the clean-up of hazardous substances at the Tremont City landfill site. Information available to DP&L does not demonstrate that it contributed hazardous substances to the site. While DP&L is unable to predict the outcome of this matter, if DP&L were required to contribute to the clean-up of the site, it could have a material adverse effect on its operations.
On April 7, 2010, the USEPA published an Advance Notice of Proposed Rulemaking announcing that it is reassessing existing regulations governing the use and distribution in commerce of polychlorinated biphenyls (PCBs). While this reassessment is in the early stages and the USEPA is evaluating information from potentially affected parties on how it should proceed, the outcome may have a material adverse effect on DP&L. The USEPA has indicated that a proposed rule will be released in late 2012. At present, DP&L is unable to predict the impact this initiative will have on its operations.
Regulation of Ash Ponds
In March 2009, the USEPA, through a formal Information Collection Request, collected information on ash pond facilities across the country, including those at Killen and J.M. Stuart stations. Subsequently, the USEPA collected similar information for the Hutchings station.
In August 2010, the USEPA conducted an inspection of the Hutchings station ash ponds. In June 2011, the USEPA issued a final report from the inspection including recommendations relative to the Hutchings station ash ponds. DP&L is unable to predict whether there will be additional USEPA action relative to DP&L’s proposed plan or the effect on operations that might arise under a different plan.
In June 2011, the USEPA conducted an inspection of the Killen station ash ponds. In June 2012, the USEPA issued a draft report from the inspection that noted no significant issues with the ash ponds. DP&L is unable to predict the outcome this inspection will have on its operations.
There has been increasing advocacy to regulate coal combustion byproducts under the Resource Conservation Recovery Act (RCRA). On June 21, 2010, the USEPA published a proposed rule seeking comments on two options under consideration for the regulation of coal combustion byproducts including regulating the material as a hazardous waste under RCRA Subtitle C or as a solid waste under RCRA Subtitle D. The USEPA anticipates issuing a final rule on this topic in late 2012. DP&L is unable to predict the financial effect of this regulation, but if coal combustion byproducts are regulated as hazardous waste, it is expected to have a material adverse effect on operations.
Notice of Violation Involving Co-Owned Plants
On September 9, 2011, DP&L received a notice of violation from the USEPA with respect to its co-owned J.M. Stuart generating station based on a compliance evaluation inspection conducted by the USEPA and Ohio EPA in 2009. The notice alleged non-compliance by DP&L with certain provisions of the RCRA, the Clean Water Act NPDES permit program and the station’s storm water pollution prevention plan. The notice requested that DP&L respond with the actions it has subsequently taken or plans to take to remedy the USEPA’s findings and ensure that further violations will not occur. Based on its review of the findings, although there can be no assurance, we believe that the notice will not result in any material effect on DP&L’s results of operations, financial condition or cash flow.
Legal and Other Matters
In February 2007, DP&L filed a lawsuit in the United States District Court for Southern District of Ohio against Appalachian Fuels, LLC (“Appalachian”) seeking damages incurred due to Appalachian’s failure to supply approximately 1.5 million tons of coal to two commonly owned plants under a coal supply agreement, of which approximately 570 thousand tons was DP&L’s share. DP&L obtained replacement coal to meet its needs. Appalachian has denied liability, and is currently in federal bankruptcy proceedings in which DP&L is participating as an unsecured creditor. DP&L is unable to determine the ultimate resolution of this matter. DP&L has not recorded any assets relating to possible recovery of costs in this lawsuit.
In connection with DP&L and other utilities joining PJM, in 2006, the FERC ordered utilities to eliminate certain charges to implement transitional payments, known as SECA, effective December 1, 2004 through March 31, 2006, subject to refund. Through this proceeding, DP&L was obligated to pay SECA charges to other utilities, but received a net benefit from these transitional payments. A hearing was held and an initial decision was issued in August 2006. A final FERC order on this issue was issued on May 21, 2010 that substantially supports DP&L’s and other utilities’ position that SECA obligations should be paid by parties that used the transmission system during the timeframe stated above. Prior to this final order being issued, DP&L entered into a significant number of bilateral settlement agreements with certain parties to resolve the matter, which by design will be unaffected by the final decision. On July 5, 2012, a Stipulation was executed and filed with the FERC that resolves SECA claims against BP Energy Company (“BP”) and DP&L, AEP (and its subsidiaries) and Exelon Corporation (and its subsidiaries). If the Stipulation is approved, DP&L would receive approximately $14.6 million from BP. DP&L will record the settlement of the BP claims once FERC approval is received. With respect to these claims, DP&L management has deferred $18.1 million and $17.8 million as of June 30, 2012 and December 31, 2011, respectively, as Other deferred credits representing the amount of unearned income and interest where the earnings process is not complete. The amount at June 30, 2012 and December 31, 2011 includes estimated earnings and interest of $5.4 million and $5.2 million, respectively.
On September 30, 2011, the FERC issued two SECA-related orders that affirmed an earlier order issued in 2010 by denying the rehearing requests that a number of different parties, including DP&L, had filed. These orders are now final, but on appeal subject to appellate court review. These orders do not affect settlements that had been reached with other parties that owed SECA revenues to DP&L or were recipients of amounts paid by DP&L. For other parties that have not yet previously settled with DP&L, the exact timing and amounts of any payments that would be made or received by DP&L under these orders is still uncertain.
Lawsuits were filed in connection with the Merger seeking, among other things, one or more of the following: to enjoin consummation of the Merger until certain conditions were met, to rescind the Merger or for rescissory damages, or to commence a sale process and/or obtain an alternative transaction or to recover an unspecified amount of other damages and costs, including attorneys’ fees and expenses, or a constructive trust or an accounting from the individual defendants for benefits they allegedly obtained as a result of their alleged breach of duty. All of these lawsuits, except one, were resolved and/or dismissed prior to the March 28, 2012 filing of our
Form 10-K for the fiscal year ending December 31, 2011, and were discussed in that and previous reports we filed. The last of these lawsuits was dismissed on March 29, 2012.
14. | Business Segments |
DPL operates through two segments consisting of the operations of two of its wholly owned subsidiaries, DP&L (Utility segment) and DPLER, including the results of DPLER’s wholly owned subsidiary, MC Squared (Competitive Retail segment). This is how we view our business and make decisions on how to allocate resources and evaluate performance.
The Utility segment is comprised of DP&L’s electric generation, transmission and distribution businesses which generate and sell electricity to residential, commercial, industrial and governmental customers. Electricity for the segment’s 24 county service area is primarily generated at eight coal-fired power plants and is distributed to more than 500,000 retail customers who are located in a 6,000 square mile area of West Central Ohio. DP&L also sells electricity to DPLER and any excess energy and capacity is sold into the wholesale market. DP&L’s transmission and distribution businesses are subject to rate regulation by federal and state regulators while rates for its generation business are deemed competitive under Ohio law.
The Competitive Retail segment is comprised of the DPLER and MC Squared competitive retail electric service businesses which sell retail electric energy under contract to residential, commercial, industrial and governmental customers who have selected DPLER or MC Squared as their alternative electric supplier. The Competitive Retail segment sells electricity to approximately 70,000 customers currently located throughout Ohio and in Illinois. In February 2011, DPLER purchased MC Squared, a Chicago-based retail electricity supplier, which serves more than 5,900 customers in Northern Illinois. At the end of the second quarter of 2012, MC Squared added approximately 29,000 new customers in Illinois cities as a result of various governmental aggregation agreements. These new customers have not yet been billed and are not included in the customer counts above. Due to increased competition in Ohio, since 2010 we have increased the number of employees and resources assigned to manage the Competitive Retail segment and increased its marketing to customers. The Competitive Retail segment’s electric energy used to meet its sales obligations was purchased from DP&L and PJM. Intercompany sales from DP&L to DPLER are based on fixed-price contracts for each DPLER customer; the price approximates market prices for wholesale power at the inception of each customer’s contract. The Competitive Retail segment has no transmission or generation assets. The operations of the Competitive Retail segment are not subject to cost-of-service rate regulation by federal or state regulators.
Included within the “Other” column are other businesses that do not meet the GAAP requirements for disclosure as reportable segments as well as certain corporate costs which include interest expense on DPL’s debt.
Management evaluates segment performance based on gross margin. The accounting policies of the reportable segments are the same as those described in Note 1 – Overview and Summary of Significant Accounting Policies. Intersegment sales and profits are eliminated in consolidation.
The following table presents financial information for each of DPL’s reportable business segments:
Successor | ||||||||||||||||||||
$ in millions | Utility | Competitive Retail | Other | Adjustments and Eliminations | DPL Consolidated | |||||||||||||||
Three Months Ended June 30, 2012 | ||||||||||||||||||||
Revenues from external customers | $ | 261.7 | $ | 109.9 | $ | 10.4 | $ | - | $ | 382.0 | ||||||||||
Intersegment revenues | 84.9 | - | 0.8 | (85.7 | ) | - | ||||||||||||||
Total revenues | 346.6 | 109.9 | 11.2 | (85.7 | ) | 382.0 | ||||||||||||||
�� | ||||||||||||||||||||
Fuel | 68.6 | - | 0.3 | - | 68.9 | |||||||||||||||
Purchased power | 69.3 | 95.5 | 0.4 | (84.9 | ) | 80.3 | ||||||||||||||
Amortization of intangibles | - | - | 19.2 | - | 19.2 | |||||||||||||||
Gross margin | $ | 208.7 | $ | 14.4 | $ | (8.7 | ) | $ | (0.8 | ) | $ | 213.6 | ||||||||
Depreciation and amortization | $ | 36.1 | $ | (0.1 | ) | $ | (4.9 | ) | $ | - | $ | 31.1 | ||||||||
Interest expense | 9.4 | 0.1 | 23.1 | (0.2 | ) | 32.4 | ||||||||||||||
Income tax expense (benefit) | 15.6 | 6.5 | (9.7 | ) | - | 12.4 | ||||||||||||||
Net income (loss) | 31.3 | 1.5 | (20.8 | ) | - | 11.9 | ||||||||||||||
Cash capital expenditures | 56.3 | 0.1 | 0.1 | - | 56.5 | |||||||||||||||
Total assets | 3,488.5 | 76.5 | 2,443.8 | - | 6,008.8 | |||||||||||||||
Predecessor | ||||||||||||||||||||
Three Months Ended June 30, 2011 | ||||||||||||||||||||
Revenues from external customers | $ | 315.9 | $ | 102.0 | $ | 15.4 | $ | - | $ | 433.3 | ||||||||||
Intersegment revenues | 81.0 | - | 1.0 | (82.0 | ) | - | ||||||||||||||
Total revenues | 396.9 | 102.0 | 16.4 | (82.0 | ) | 433.3 | ||||||||||||||
Fuel | 89.1 | - | 3.0 | - | 92.1 | |||||||||||||||
Purchased power | 104.4 | 89.5 | 0.7 | (81.0 | ) | 113.6 | ||||||||||||||
Gross margin | $ | 203.4 | $ | 12.5 | $ | 12.7 | $ | (1.0 | ) | $ | 227.6 | |||||||||
Depreciation and amortization | $ | 33.4 | $ | - | $ | 1.7 | $ | - | $ | 35.1 | ||||||||||
Interest expense | 9.7 | 0.1 | 7.9 | (0.1 | ) | 17.6 | ||||||||||||||
Income tax expense (benefit) | 15.5 | 3.3 | (2.5 | ) | - | 16.3 | ||||||||||||||
Net income (loss) | 30.8 | 5.7 | (3.7 | ) | (1.1 | ) | 31.7 | |||||||||||||
Cash capital expenditures | 48.4 | - | - | - | 48.4 | |||||||||||||||
Year Ended December 31, 2011 | ||||||||||||||||||||
Total assets | 3,525.7 | 69.9 | 2,501.5 | - | 6,097.1 |
Successor | ||||||||||||||||||||
$ in millions | Utility | Competitive Retail | Other | Adjustments and Eliminations | DPL Consolidated | |||||||||||||||
Six Months Ended June 30, 2012 | ||||||||||||||||||||
Revenues from external customers | $ | 574.5 | $ | 222.0 | $ | 19.5 | $ | - | $ | 816.0 | ||||||||||
Intersegment revenues | 171.7 | - | 1.7 | (173.4 | ) | - | ||||||||||||||
Total revenues | 746.2 | 222.0 | 21.2 | (173.4 | ) | 816.0 | ||||||||||||||
Fuel | 164.2 | - | 2.1 | - | 166.3 | |||||||||||||||
Purchased power | 154.2 | 192.2 | 0.4 | (171.7 | ) | 175.1 | ||||||||||||||
Amortization of intangibles | - | - | 47.0 | - | 47.0 | |||||||||||||||
Gross margin | $ | 427.8 | $ | 29.8 | $ | (28.3 | ) | $ | (1.7 | ) | $ | 427.6 | ||||||||
Depreciation and amortization | $ | 70.8 | $ | 0.1 | $ | (8.4 | ) | $ | - | $ | 62.5 | |||||||||
Interest expense | 19.0 | 0.3 | 43.1 | (0.4 | ) | 62.0 | ||||||||||||||
Income tax expense (benefit) | 32.9 | 9.9 | (22.7 | ) | - | 20.1 | ||||||||||||||
Net income (loss) | 69.4 | 7.5 | (43.3 | ) | - | 33.6 | ||||||||||||||
Cash capital expenditures | 109.5 | 0.5 | 0.5 | - | 110.5 | |||||||||||||||
Total assets | 3,488.5 | 76.5 | 2,443.8 | - | 6,008.8 | |||||||||||||||
Predecessor | ||||||||||||||||||||
Six Months Ended June 30, 2011 | ||||||||||||||||||||
Revenues from external customers | $ | 690.6 | $ | 196.0 | $ | 27.3 | $ | - | $ | 913.9 | ||||||||||
Intersegment revenues | 156.1 | - | 2.0 | (158.1 | ) | - | ||||||||||||||
Total revenues | 846.7 | 196.0 | 29.3 | (158.1 | ) | 913.9 | ||||||||||||||
Fuel | 187.7 | - | 4.2 | - | 191.9 | |||||||||||||||
Purchased power | 222.2 | 167.2 | 1.1 | (156.1 | ) | 234.4 | ||||||||||||||
Gross margin | $ | 436.8 | $ | 28.8 | $ | 24.0 | $ | (2.0 | ) | $ | 487.6 | |||||||||
Depreciation and amortization | $ | 66.5 | $ | 0.1 | $ | 3.6 | $ | - | $ | 70.2 | ||||||||||
Interest expense | 19.4 | 0.1 | 15.1 | (0.1 | ) | 34.5 | ||||||||||||||
Income tax expense (benefit) | 42.5 | 9.9 | (11.3 | ) | - | 41.1 | ||||||||||||||
Net income (loss) | 83.5 | 11.8 | (18.5 | ) | (1.6 | ) | 75.2 | |||||||||||||
Cash capital expenditures | 90.8 | - | 0.6 | - | 91.4 | |||||||||||||||
Year Ended December 31, 2011 | ||||||||||||||||||||
Total assets | 3,525.7 | 69.9 | 2,501.5 | - | 6,097.1 |
Benchmarking Companies Towers Watson 2010 Energy Services Executive Database | ||||||
AEI Services | DPL | MDU Resources | Regency Energy Partners LP | |||
Allegheny Energy | DTE Energy | Midwest Independent Transmission System Operator | RRI Energy | |||
Allete | Duke Energy | Mirant | Salt River Project | |||
Alliant Energy | E.ON U.S. | New York Independent System Operator | Santee Cooper | |||
Ameren | Edison International | New York Power Authority | SCANA | |||
American Electric Power | El Paso Corporation | Nicor | Sempra Energy | |||
Areva | Electric Power Research Institute | Northeast Utilities | Southern Company Services | |||
ATC Management | Enbridge Energy | NorthWestern Energy | Southern Maryland Electric Cooperative | |||
Atmos Energy | Energen | NRG Energy | Southern Union Company | |||
Avista | Energy Future Holdings | NSTAR | Southwest Power Pool | |||
BG US Services | Energy Northwest | NV Energy | Spectra Energy | |||
Black Hills Power and Light | Entergy | NW Natural | STP Nuclear Operating | |||
California Independent System Operator | EPCO | OGE Energy | Targa Resources | |||
Calpine | ERCOT | Oglethorpe Power | Tennessee Valley Authority | |||
CenterPoint Energy | Exelon | Omaha Public Power | TransCanada | |||
CH Energy Group | First Solar | Pacific Gas & Electric | UIL Holdings | |||
Cleco | FirstEnergy | Pepco Holdings | UniSource Energy | |||
CMS Energy | FPL Group | Pinnacle West Capital | Unitil | |||
Colorado Springs Utilities | GDF SUEZ Energy North America | PJM Interconnection | Vectren | |||
Consolidated Edison | Hawaiian Electric | PNM Resources | Westar Energy | |||
Constellation Energy | IDACORP | Portland General Electric | Westinghouse Electric | |||
Covanta Holdings | lntegrys Energy Group | PPL | Wisconsin Energy | |||
CPS Energy | ISO New England | Progress Energy | Wolf Creek Nuclear | |||
DCP Midstream | Kinder Morgan | Proliance Holdings | Xcel Energy | |||
Direct Energy | LES | Public Service Enterprise Group | ||||
Dominion Resources | Lower Colorado River Authority | Puget Energy |
Benchmarking Companies Towers Watson 2010 General Industry Executive Database | ||||||
3M | Armstrong World Industries | Cardinal Health | Cox Enterprises | |||
7-Eleven | Arrow Electronics | CareFusion | Crown Castle | |||
A&P | AstraZeneca | Cargill | CSR | |||
A. H. Belo | AT&T | Carlson Companies | CSX | |||
A.O. Smith | Automatic Data Processing | Carnival | CVS Caremark | |||
A.T. Cross | Avanade | Carpenter Technology | Cytec | |||
Abbott Laboratories | Avis Budget Group | Catalent Pharma Solutions | Daiichi Sankyo | |||
Accenture | Ball | Celgene | Dana | |||
ACH Food | Barnes Group | Cemex | Dannon | |||
Acuity Brands | Barrick Gold of North America | CenturyLink | Darden Restaurants | |||
Aeropostale | Baxter International | Cephalon | Day & Zimmermann | |||
Agilent Technologies | Bayer CropScience | CF Industries | Dean Foods | |||
Agrium | Beckman Coulter | CH2M Hill | Del Monte Foods | |||
Air Liquide | Belo | Chemtura | Dell | |||
Air Products and Chemicals | Best Buy | Chiquita Brands | Delta Air Lines | |||
Alcatel Lucent | Big Lots | Choice Hotels International | Deluxe | |||
Alcoa | Biogen Idec | CHS | Denny's | |||
Alcon Laboratories | BJ's Wholesale Club | Cimarex Energy | Dentsply | |||
Alexander & Baldwin | Blockbuster | Cintas | Dex One | |||
Allergan | Blyth | Cisco Systems | Diageo North America | |||
Alliant Techsystems | Boehringer Ingelheim | Cliffs Natural Resources | Dionex | |||
Amazon.com | Boston Scientific | COACH | Domtar | |||
American Crystal Sugar | Bovis Lend Lease | Coca-Cola | Donaldson | |||
Ameron | Brady | Colgate-Palmolive | Dow Chemical | |||
AMETEK | Bristol-Myers Squibb | Columbia Sportswear | Dow Corning | |||
Amgen | Broadcom | ConAgra Foods | DuPont | |||
AOL | Burlington Northern Santa Fe | Continental Automotive Systems | E.W. Scripps | |||
APL | Bush Brothers | ConvaTec | Eastman Chemical | |||
Appleton Papers | C.H. Robinson Worldwide | Convergys | Eaton | |||
Applied Materials | Cadbury | Cooper Industries | Ecolab | |||
ARAMARK | Calgon Carbon | Corning | Eisai | |||
Archer Daniels Midland | Callaway Golf | Covance | Eli Lilly | |||
Arctic Cat | Cameron International | Covidien | EMC |
EMCOR Group | Goodyear Tire & Rubber | IDEXX Laboratories | L-3 Communications | |||
EMI Music | Gorton's | IKON Office Solutions | Lafarge North America | |||
Equifax | Graco | IMS Health | Lance | |||
Equity Office Properties | Greif | Infragistics | Land O'Lakes | |||
Essilor of America | Gruma | Intel | Lear | |||
Evergreen Packaging | Grupo Ferrovial | Intercontinental Hotels | Leggett & Platt | |||
Express Scripts | GTECH | International Flavors & Fragrances | Level 3 Communications | |||
Exterran | GXS | International Paper | Levi Strauss | |||
Fair Isaac | H. J. Heinz | Invensys Controls | Life Technologies | |||
Fairchild Controls | H.B. Fuller | ION Geophysical | Lockheed Martin | |||
FANUC Robotics America | Hanesbrands | Iron Mountain | Lorillard Tobacco | |||
Federal-Mogul | Hannaford | Irvine Company | MAG Industrial Automation Systems | |||
Fidelity National Information Services | Harland Clarke | ITT | Magellan Midstream Partners | |||
First Solar | Harley-Davidson | J. Crew | Marriott International | |||
Fiserv | Hasbro | J.M. Smucker | Martin Marietta Materials | |||
Flowserve | HBO | J.R. Simplot | Mary Kay | |||
Fluor | Henkel of America | Jabil Circuit | Masco | |||
Ford | Herman Miller | Jack in the Box | Mattel | |||
Forest Laboratories | Hershey | Jacobs Engineering | Matthews International | |||
Fortune Brands | Hertz | JM Family | McClatchy | |||
Freeport-McMoRan Copper & Gold | Hewlett Packard | Johnson & Johnson | McDermott | |||
GAF Materials | Hilton Worldwide | Johnson Controls | McDonald's | |||
Gap | Hitachi Data Systems | Kaman Industrial Technologies | McGraw-Hill | |||
GATX | HNI | KBR | McKesson | |||
Gavilon | HNTB | Kellogg | MeadWestvaco | |||
General Atomics | Hoffmann-La Roche | Kimberly-Clark | Medicines Company | |||
General Dynamics | Honeywell | King Pharmaceuticals | MedImmune | |||
General Mills | Hormel Foods | Kinross Gold | Medtronic | |||
General Motors | Hospira | KLA - Tencor | Merck & Co. | |||
Genzyme | Houghton Mifflin Harcourt Publishing | Knowles Electronics | Microsoft | |||
Getty Images | Hunt Consolidated | Koch Industries | Milacron | |||
Gilead Sciences | Husky Injection Molding Systems | Kohler | Millipore | |||
GlaxoSmithKline | Hyatt Hotels | Kohl's | Mine Safety Appliances | |||
Goodrich | IBM | L.L. Bean | Mizuno USA |
Molson Coors Brewing | PerkinElmer | SAS Institute | Synacor | |||
Molycorp Minerals | Pervasive Software | SCA Americas | Takeda Pharmaceutical Company Limited | |||
Monsanto | PetSmart | Schlumberger | Target | |||
Mosaic | Pfizer | Schreiber Foods | Taubman Centers | |||
Motorola | Pitney Bowes | Schwan's | Tellabs | |||
Murphy Oil | Pittsburgh Corning | Seagate Technology | Temple-Inland | |||
MWH Global | Plexus | Sealed Air | Teradata | |||
Navistar International | Polaris Industries | Sensata Technologies | Terex | |||
Nestlé USA | Polymer Group | Sensient Technologies | Textron | |||
NetJets | PolyOne | Sherwin-Williams | Thomas & Betts | |||
New York Times | Potash | Shire Pharmaceuticals | Time Warner | |||
Newmont Mining | PPG Industries | Siemens | Time Warner Cable | |||
NewPage | Praxair | Simpson Manufacturing | Timken | |||
NIKE | Pulte Homes | Sirius XM Radio | T-Mobile USA | |||
Nissan North America | Purdue Pharma | Skype | Toro | |||
Nokia | QUALCOMM | Smith & Nephew | Total System Services | |||
Noranda Aluminum | Quest Diagnostics | Smurfit-Stone Container | Trinity Industries | |||
Norfolk Southern | Quintiles | Snap-On | TRW Automotive | |||
Northrop Grumman | R.R. Donnelley | Sodexo | TUI | |||
Novartis | Ralcorp Holdings | Sonoco Products | Tupperware | |||
Novartis Consumer Health | Redcats USA | Sony Corporation | Tyco Electronics | |||
Novell | Reddy Ice | Spirit AeroSystems | U.S. Foodservice | |||
Novo Nordisk Pharmaceuticals | Revlon | Sprint Nextel | Unifi | |||
Nycomed US | RF Micro Devices | SPX | Unilever United States | |||
Nypro | Rio Tinto | SRA International | Union Pacific | |||
Occidental Petroleum | Roche Diagnostics | Stantec | Unisys | |||
Office Depot | Rockwell Automation | Starbucks | United Airlines | |||
Orange Business Services | Rockwell Collins | StarTek | United Parcel Service | |||
Oshkosh | Ryder System | Starwood Hotels & Resorts | United Rentals | |||
Owens Corning | S.C. Johnson | Steelcase | United States Cellular | |||
Owens-Illinois | Safety-Kleen Systems | Stryker | United States Steel | |||
Parker Hannifin | SAIC | Sunoco | United Technologies | |||
Parsons | Sanofi-Aventis | Swagelok | USG | |||
PepsiCo | Sanofi-Pasteur | Sybron Dental Specialties | Valero Energy |
Verde Realty | Vistar | Watson Pharmaceuticals | Wyndham Worldwide | |||
Verizon | Visteon | Watts Water Technologies | Yahoo! | |||
Vertex Pharmaceuticals | Volvo Group North America | Wendy's/Arby's Group | YRC Worldwide | |||
VF | Vulcan Materials | Western Digital | Yum! Brands | |||
Viacom | VWR International | Weyerhaeuser | Zale | |||
Village Farms | Walt Disney | Whole Foods Market | ||||
Vision Service Plan | Waste Management | Wm. Wrigley Jr. |
DPL INC.
Offer to Exchange
6.50% Senior Notes due 2016
7.25% Senior Notes due 2021
for
New 6.50% Senior Notes Due 2016
New 7.25% Senior Notes due 2021
Until , all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters with respect to their unsold allotments or subscriptions.
PROSPECTUS
, 2012
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
Item 20. Indemnification of Directors and Officers.
Article VIII of the Amended Regulations of DPL Inc. (the “Company”), as amended through November 28, 2011, provides for indemnification rights to directors, officers, employees or agents of the Company, or individuals who serve at the request of the Company as a director, trustee, officer, employee or agent for other entities. Article VIII provides that indemnification shall be available to the full extent permitted by law including, without limitation, Section 1701.13(E) of the Ohio Revised Code. The Amended Regulations further provide that the indemnification rights set forth in Article VIII are not exclusive of any rights to which those seeking indemnification may be entitled under the Company’s Amended Articles of Incorporation or the Amended Regulations or any agreement, vote of shareholders or disinterested directors, or otherwise. The Company’s Amended Articles of Incorporation and Amended Regulations are exhibits to this registration statement.
Section 1701.13(E) of the Ohio Revised Code provides as follows:
(E) (1) A corporation may indemnify or agree to indemnify any person who was or is a party, or is threatened to be made a party, to any threatened, pending, or completed action, suit, or proceeding, whether civil, criminal, administrative, or investigative, other than an action by or in the right of the corporation, by reason of the fact that he is or was a director, officer, employee, or agent of the corporation, or is or was serving at the request of the corporation as a director, trustee, officer, employee, member, manager, or agent of another corporation, domestic or foreign, nonprofit or for profit, a limited liability company, or a partnership, joint venture, trust, or other enterprise, against expenses, including attorney's fees, judgments, fines, and amounts paid in settlement actually and reasonably incurred by him in connection with such action, suit, or proceeding, if he acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the corporation, and, with respect to any criminal action or proceeding, if he had no reasonable cause to believe his conduct was unlawful. The termination of any action, suit, or proceeding by judgment, order, settlement, or conviction, or upon a plea of nolo contendere or its equivalent, shall not, of itself, create a presumption that the person did not act in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the corporation, and, with respect to any criminal action or proceeding, he had reasonable cause to believe that his conduct was unlawful.
(2) A corporation may indemnify or agree to indemnify any person who was or is a party, or is threatened to be made a party, to any threatened, pending, or completed action or suit by or in the right of the corporation to procure a judgment in its favor, by reason of the fact that he is or was a director, officer, employee, or agent of the corporation, or is or was serving at the request of the corporation as a director, trustee, officer, employee, member, manager, or agent of another corporation, domestic or foreign, nonprofit or for profit, a limited liability company, or a partnership, joint venture, trust, or other enterprise, against expenses, including attorney's fees, actually and reasonably incurred by him in connection with the defense or settlement of such action or suit, if he acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the corporation, except that no indemnification shall be made in respect of any of the following:
(a) Any claim, issue, or matter as to which such person is adjudged to be liable for negligence or misconduct in the performance of his duty to the corporation unless, and only to the extent that, the court of common pleas or the court in which such action or suit was brought determines, upon application, that, despite the adjudication of liability, but in view of all the circumstances of the case, such person is fairly and reasonably entitled to indemnity for such expenses as the court of common pleas or such other court shall deem proper;
(b) Any action or suit in which the only liability asserted against a director is pursuant to section 1701.95 of the Revised Code.
(3) To the extent that a director, trustee, officer, employee, member, manager, or agent has been successful on the merits or otherwise in defense of any action, suit, or proceeding referred to in division (E)(1) or (2) of this section, or in defense of any claim, issue, or matter therein, he shall be indemnified against expenses,
including attorney's fees, actually and reasonably incurred by him in connection with the action, suit, or proceeding.
(4) Any indemnification under division (E)(1) or (2) of this section, unless ordered by a court, shall be made by the corporation only as authorized in the specific case, upon a determination that indemnification of the director, trustee, officer, employee, member, manager, or agent is proper in the circumstances because he has met the applicable standard of conduct set forth in division (E)(1) or (2) of this section. Such determination shall be made as follows:
(a) By a majority vote of a quorum consisting of directors of the indemnifying corporation who were not and are not parties to or threatened with the action, suit, or proceeding referred to in division (E)(1) or (2) of this section;
(b) If the quorum described in division (E)(4)(a) of this section is not obtainable or if a majority vote of a quorum of disinterested directors so directs, in a written opinion by independent legal counsel other than an attorney, or a firm having associated with it an attorney, who has been retained by or who has performed services for the corporation or any person to be indemnified within the past five years;
(c) By the shareholders;
(d) By the court of common pleas or the court in which the action, suit, or proceeding referred to in division (E)(1) or (2) of this section was brought.
Any determination made by the disinterested directors under division (E)(4)(a) or by independent legal counsel under division (E)(4)(b) of this section shall be promptly communicated to the person who threatened or brought the action or suit by or in the right of the corporation under division (E)(2) of this section, and, within ten days after receipt of such notification, such person shall have the right to petition the court of common pleas or the court in which such action or suit was brought to review the reasonableness of such determination.
(5) | (a) | Unless at the time of a director's act or omission that is the subject of an action, suit, or proceeding referred to in division (E)(1) or (2) of this section, the articles or the regulations of a corporation state, by specific reference to this division, that the provisions of this division do not apply to the corporation and unless the only liability asserted against a director in an action, suit, or proceeding referred to in division (E)(1) or (2) of this section is pursuant to section 1701.95 of the Revised Code, expenses, including attorney's fees, incurred by a director in defending the action, suit, or proceeding shall be paid by the corporation as they are incurred, in advance of the final disposition of the action, suit, or proceeding, upon receipt of an undertaking by or on behalf of the director in which he agrees to do both of the following: |
(i) Repay such amount if it is proved by clear and convincing evidence in a court of competent jurisdiction that his action or failure to act involved an act or omission undertaken with deliberate intent to cause injury to the corporation or undertaken with reckless disregard for the best interests of the corporation;
(ii) Reasonably cooperate with the corporation concerning the action, suit, or proceeding.
(b) | Expenses, including attorney's fees, incurred by a director, trustee, officer, employee, member, manager, or agent in defending any action, suit, or proceeding referred to in division (E)(1) or (2) of this section, may be paid by the corporation as they are incurred, in advance of the final disposition of the action, suit, or proceeding, as authorized by the directors in the specific case, upon receipt of an undertaking by or on behalf of the director, trustee, officer, employee, member, manager, or agent to repay such amount, if it ultimately is determined that he is not entitled to be indemnified by the corporation. |
(6) The indemnification authorized by this section shall not be exclusive of, and shall be in addition to, any other rights granted to those seeking indemnification under the articles, the regulations, any agreement, a vote of shareholders or disinterested directors, or otherwise, both as to action in their official capacities and as to action in another capacity while holding their offices or positions, and shall continue as to a person
who has ceased to be a director, trustee, officer, employee, member, manager, or agent and shall inure to the benefit of the heirs, executors, and administrators of such a person.
(7) A corporation may purchase and maintain insurance or furnish similar protection, including, but not limited to, trust funds, letters of credit, or self-insurance, on behalf of or for any person who is or was a director, officer, employee, or agent of the corporation, or is or was serving at the request of the corporation as a director, trustee, officer, employee, member, manager, or agent of another corporation, domestic or foreign, nonprofit or for profit, a limited liability company, or a partnership, joint venture, trust, or other enterprise, against any liability asserted against him and incurred by him in any such capacity, or arising out of his status as such, whether or not the corporation would have the power to indemnify him against such liability under this section. Insurance may be purchased from or maintained with a person in which the corporation has a financial interest.
(8) The authority of a corporation to indemnify persons pursuant to division (E)(1) or (2) of this section does not limit the payment of expenses as they are incurred, indemnification, insurance, or other protection that may be provided pursuant to divisions (E)(5), (6), and (7) of this section. Divisions (E)(1) and (2) of this section do not create any obligation to repay or return payments made by the corporation pursuant to division (E)(5), (6), or (7).
(9) As used in division (E) of this section, “corporation” includes all constituent entities in a consolidation or merger and the new or surviving corporation, so that any person who is or was a director, officer, employee, trustee, member, manager, or agent of such a constituent entity, or is or was serving at the request of such constituent entity as a director, trustee, officer, employee, member, manager, or agent of another corporation, domestic or foreign, nonprofit or for profit, a limited liability company, or a partnership, joint venture, trust, or other enterprise, shall stand in the same position under this section with respect to the new or surviving corporation as he would if he had served the new or surviving corporation in the same capacity.
DPL Inc. maintains standard policies of insurance under which coverage is provided to its directors and officers against loss rising from claims made by reason of breach of duty or other wrongful act, and to DPL Inc. with respect to payments which may be made by DPL Inc. to such officers and directors pursuant to the above indemnification provision or otherwise as a matter of law.
The Registration Rights Agreement filed as Exhibit 4.14 to this prospectus provides for indemnification of directors and officers of DPL Inc. by the initial purchasers against certain liabilities.
Item 21. Exhibits and Financial Statement Schedules
Exhibit No. | Document | |
2.1 | Agreement and Plan of Merger, dated as of April 19, 2011, by and among DPL Inc., The AES Corporation and Dolphin Sub, Inc. | |
3.1 | Amended Articles of Incorporation of DPL Inc., as amended through January 6, 2012 | |
3.2 | Amended Regulations of DPL Inc., as amended through November 28, 2011 | |
4.1 | Composite Indenture dated as of October 1, 1935, between The Dayton Power and Light Company and Irving Trust Company, Trustee with all amendments through the Twenty-Ninth Supplemental Indenture | |
4.2 | Thirty-Second Supplemental Indenture dated as of November 1, 1982 between The Dayton Power and Light Company and Irving Trust Company, Trustee | |
4.3 | Fortieth Supplemental Indenture dated as of February 15, 1993, between The Dayton Power and Light Company and The Bank of New York, Trustee | |
4.4 | Forty-First Supplemental Indenture dated as of February 1, 1999, between The Dayton Power and Light Company and The Bank of New York, Trustee | |
4.5 | Forty-Second Supplemental Indenture dated as of September 1, 2003, between The Dayton Power and Light Company and The Bank of New York, Trustee | |
4.6 | Forty-Third Supplemental Indenture dated as of August 1, 2005, between The Dayton Power and Light Company and The Bank of New York, Trustee | |
4.7 | Indenture dated as of August 31, 2001 between DPL Inc. and The Bank of New York, Trustee | |
4.8 | First Supplemental Indenture dated as of August 31, 2001 between DPL Inc. and The Bank of New York, as Trustee | |
4.9 | Amended and Restated Trust Agreement dated as of August 31, 2001 among DPL Inc., The Bank of New York, The Bank of New York (Delaware), the administrative trustees named therein, and several Holders as defined therein |
Exhibit No. | Document | |
4.10 | Forty-Fourth Supplemental Indenture dated as of September 1, 2006 between the Bank of New York, Trustee and The Dayton Power and Light Company | |
4.11 | Forty-Sixth Supplemental Indenture dated as of December 1, 2008 between The Bank of New York Mellon, Trustee and The Dayton Power and Light Company | |
4.12 | Indenture, dated October 3, 2011, between Dolphin Subsidiary II, Inc. and Wells Fargo Bank, National Association | |
4.13 | Supplemental Indenture, dated as of November 28, 2011, between DPL Inc. and Wells Fargo Bank, National Association | |
4.14 | Registration Rights Agreement, dated October 3, 2011, between Dolphin Subsidiary II, Inc. and Merrill Lynch Pierce Fenner & Smith Incorporated and each of the initial purchasers named therein | |
5.1 | Opinion of Davis Polk & Wardwell LLP | |
10.1 | Credit Agreement, dated as of April 20, 2010, among The Dayton Power and Light Company, Bank of America, N.A., as Administrative Agent and an L/C Issuer, and the lenders party to the Credit Agreement | |
10.2 | Limited Consent and Waiver, dated as of May 24, 2011, to the Credit Agreement, dated as of April 20, 2010, among The Dayton Power and Light Company, Bank of America, N.A., as Administrative Agent and an L/C Issuer, and the lenders party to the Credit Agreement | |
10.3 | First Amendment Agreement, dated as of November 18, 2011, to the Credit Agreement, dated as of April 20, 2010, among The Dayton Power and Light Company, Bank of America, N.A., as Administrative Agent and an L/C Issuer, and the lenders party to the Credit Agreement | |
10.4 | Credit Agreement, dated as of August 24, 2011, among DPL Inc., PNC Bank, National Association, as Administrative Agent, Bank of America, N.A., Fifth Third Bank and U.S. Bank, National Association, as Co-Syndication Agents, Bank of America, N.A., as Documentation Agent, and the lenders party to the Credit Agreement | |
10.5 | Credit Agreement, dated as of August 24, 2011, among DPL Inc., U.S. Bank, National Association, as Administrative Agent, Swing Line Lender and an L/C Issuer, Bank of America, N.A., Fifth Third Bank and PNC Bank, National Association, as Co-Syndication Agents, Bank of America, N.A., as Documentation Agent, and the lenders party to the Credit Agreement | |
10.6 | Credit Agreement, dated as of August 24, 2011, among The Dayton Power and Light Company, Fifth Third Bank, as Administrative Agent, Swing Line Lender and an L/C Issuer, Bank of America, N.A., U.S. Bank, National Association and PNC Bank, National Association, as Co-Syndication Agents, Bank of America, N.A., as Documentation Agent, and the lenders party to the Credit Agreement | |
12.1 | Statement of Computation of Ratio of Earnings to Fixed Charges | |
21.1 | List of Significant Subsidiaries of DPL Inc. | |
23.1 | Consent of Independent Registered Accounting Firm, Ernst & Young LLP | |
23.2 | Consent of Independent Registered Accounting Firm, KPMG LLP | |
23.3 | Consent of Davis Polk & Wardwell LLP (contained in their opinion in Exhibit 5.1) | |
24.1 | Powers of Attorney (included on signature page to registration statement) | |
25.1 | Statement of Eligibility of Wells Fargo Bank, N.A., as Trustee, on Form T-1 | |
99.1 | Form of Letter of Transmittal | |
99.2 | Form of Notice of Guaranteed Delivery | |
99.3 | Form of Letter to Clients | |
99.4 | Form of Letter to Brokers | |
99.5 | Form of Instructions to Registered Holder and/or Book-Entry Transfer Participant from Owner |
101.INS | XBRL Instance | |
101.SCH | XBRL Taxonomy Extension Schema | |
101.CAL | XBRL Taxonomy Extension Calculation Linkbase | |
101.DEF | XBRL Taxonomy Extension Definition Linkbase | |
101.LAB | XBRL Taxonomy Extension Label Linkbase | |
101.PRE | XBRL Taxonomy Extension Presentation Linkbase |
Item 22. Undertakings
(a) The undersigned hereby undertakes:
(1) To file during any period in which offers or sales are being made, a post-effective amendment to this registration statement:
(i) to include any prospectus required by Section 10(a)(3) of the Securities Act of 1933;
(ii) to reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in the volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than a 20 percent change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement; and
(iii) to include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement;
provided, however, that paragraphs (a)(1)(i) and (a)(1)(ii) do not apply if the registration statement is on Form S-3, Form S-8 or Form F-3, and the information required to be included in a post-effective amendment by those paragraphs is contained in periodic reports filed with or furnished to the Commission by the registrant pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 that are incorporated by reference in the registration statement.
(2) That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.
(3) To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.
(4) That, for the purpose of determining liability under the Securities Act of 1933 to any purchaser, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness; provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, superseded or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.
(5) That, for the purpose of determining liability of the registrant under the Securities Act of 1933 to any purchaser in the initial distribution of the securities: The undersigned registrant undertakes that in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser: (i) any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424; (ii) any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant; (iii) the portion of any other free writing prospectus relating to the offering containing material information about the undersigned
registrant or its securities provided by or on behalf of the undersigned registrant; and (iv) any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.
(b) Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to our directors, officers and controlling persons pursuant to the foregoing provisions, or otherwise, we have been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by us of expenses incurred or paid by one of our directors, officers or controlling persons in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, we will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.
(c) The undersigned hereby undertakes to respond to requests for information that is incorporated by reference into the prospectus pursuant to Item 4, 10(b), 11 or 13 of this form, within one business day of receipt of such request, and to send the incorporated documents by first class mail or other equally prompt means. This includes information contained in documents filed subsequent to the effective date of the registration statement through the date of responding to the request.
(d) The undersigned hereby undertakes to supply by means of a post-effective amendment all information concerning a transaction and the company being acquired involved therein, that was not the subject of and included in the registration statement when it became effective.
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended, DPL Inc. has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Dayton, State of Ohio, on August 24, 2012.
DPL INC. | |||
By: | /s/ Philip R. Herrington | ||
Name: | Philip R. Herrington | ||
Title: | President and Chief Executive Officer |
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Timothy G. Rice and Craig L. Jackson, and each of them, his or her true and lawful attorneys-in-fact and agents, with full power to act separately and full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this registration statement and all additional registration statements pursuant to Rule 462(b) of the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto each said attorney-in-fact and agent full power and authority to do and perform each and every act in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or either of them or his or her or their substitute or substitutes may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Act of 1933, as amended, this registration statement has been signed by the following persons in the capacities and on the dates indicated.
Signature | Title | Date | |
/s/ Philip R. Herrington | President and Chief Executive Officer (Principal Executive Officer) and Director | August 24, 2012 | |
Philip R. Herrington | |||
/s/ Craig L. Jackson | Senior Vice President and Chief Financial Officer (Principal Financial Officer) | August 24, 2012 | |
Craig L. Jackson | |||
/s/ Gregory S. Campbell | Vice President and Controller (Principal Accounting Officer) | August 24, 2012 | |
Gregory S. Campbell | |||
/s/ Andrew M. Vesey | Chairman of the Board | August 24, 2012 | |
Andrew M. Vesey | |||
/s/ Brian A. Miller | Director | August 24, 2012 | |
Brian A. Miller | |||
Director | |||
Mary S. Stawikey |
II-8